2008 

Fact 

Book

43rd EEI 

Financial Financial 

Conference Conference

Phoenix, AZ Phoenix, AZ

2

Table of Contents

Safe Harbor Statement & IR Contacts

Company Overview Tab 1

Operating Company Overview Tab 2

Organizational Structure

AEP East Regional Utilities

AEP West Regional Utilities

Regulation Tab 3

Regulatory Strategy

Rate Case Filing Requirements

Regulatory Activity Underway

GridSMART Regulatory Status 

Rate Base and ROE by Operating Company

Commission Overviews

Generation & Environmental Tab 4

Units

Generation Statistics

New Generation

Environmental

Future Potential Green House Gas Regulations

Coal Tab 5

Coal Procurement, Delivery & Transportation

Fuel Recovery

Coal Market Information

Transmission Initiatives Tab 6

Financial Update Tab 7

Capitalization

Liquidity Position

Credit Ratings

Long-Term Debt Maturity Profile

Debt Schedules
3

This presentation contains forward-looking statements, which are subject to risks and uncertainties. These factors 

include electric load and customer growth; weather conditions, including storms; available sources and costs of, and 

transportation for, fuels and performance of fuel suppliers and transporters; availability of generating capacity and 

performance of generating plants; the ability to recover regulatory assets and stranded costs in connection with 

deregulation; the ability to recover increases in fuel and other energy costs through regulated or competitive electric 

rates; the ability to build or acquire generating capacity (including our ability to obtain any necessary regulatory 

approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of 

projects that are cancelled) through applicable rate cases or competitive rates; new legislation, litigation and 

government regulation, including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or 

particulate matter and other substances; timing and resolution of pending and future rate cases, negotiations and 

other regulatory decisions (including rate or other recovery of new investments in generation, distribution and 

transmission service and environmental compliance); resolution of litigation (including disputes arising from the 

bankruptcy of Enron Corp. and related matters); our ability to constrain operation and maintenance costs; the 

economic climate and growth or contraction in our service territory and changes in market demand and demographic 

patterns; inflationary and interest rate trends; volatility in the financial markets, particularly development affecting 

the availability of capital on reasonable terms and developments impacting our ability to refinance existing debt at 

attractive rates; our ability to develop and execute a strategy based on a view regarding prices of electricity, natural 

gas coal, nuclear fuel and other energy related commodities; changes in the creditworthiness of the counterparties 

with whom we have contractual arrangements, including participants in the energy trading market; actions of rating 

agencies, including changes in the ratings of debt; volatility and changes in markets for electricity, natural gas and 

other energy-related commodities; changes in utility regulation, including the implementation of the recently-passed 

utility law in Ohio and the allocation of costs within regional transmission organizations; accounting pronouncements 

periodically issued by accounting standard-setting bodies; the impact of volatility in the capital markets on the value 

of the investments held by our pension, other postretirement benefit plans and nuclear decommissioning trust and the 

impact on future funding requirements; prices for power we generate and sell at wholesale; changes in technology, 

particularly with respect to new, developing or alternative sources of generation; other risks and unforeseen events, 

including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events; 

and other factors discussed in the reports, including Forms 10-K and 10-Q, filed from time to time by the company 

with the SEC.

Investor Relations Contacts

Chuck Zebula

Treasurer

SVP Investor Relations

614-716-2801

cezebula@aep.com

Bette Jo Rozsa

Managing Director

Investor Relations

614-716-2840

bjrozsa@aep.com

Julie Sherwood

Director

Investor Relations

614-716-2663

jasherwood@aep.com

“Safe Harbor” Statement under the Private 

Securities Litigation Reform Act of 1995

Jana Croom

Analyst

Investor Relations

614-716-3175

jtcroom@aep.com
Operating Company

Overview Regulation

Generation &

Environmental Company Overview Coal
Company Overview

Fall EEI 2008

4

5

Company Overview

American Electric Power Company, Inc. is one of the largest investor-owned electric public utility holding companies in the US. We 

provide generation, transmission and distribution services to over 5 million retail customers in eleven states (Arkansas, Indiana, 

Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our electric utility operating 

companies. 

We have seven regional operating companies for distribution and customer service operations 

that serve the customers of our eleven electric utility subsidiaries:

Regional Utility Divisions

Columbus Southern PowerOhio PowerWheeling PowerTexas Central CompanyTexas North CompanyAppalachian Power Kingsport Power

Indiana Michigan Power

Kentucky Power

Public Service Company of Oklahoma

Southwestern Electric Power Co.

AEP Ohio

AEP Texas

Appalachian Power

Indiana Michigan PowerKentucky PowerPublic Service Company of Oklahoma

Southwestern Electric Power Co.

Electric Utility Subsidiaries

OUR FOCUS IS OUR CORE 

DOMESTIC UTILITY BUSINESS OPERATIONS
6

Company Overview

We consume approximately 76 million tons of coal annually.

Almost 39,000 megawatts of generating capacity in 3 RTOs (one of the largest US generation portfolios with a significant cost advantage in many of our market areas)Approximately 39,000 circuit miles of transmission lines, including 2,116 miles of 765kV lines, the backbone of the electric interconnection grid in the Eastern U.S.212,781 miles of overhead and underground distribution lines

Our US electric assets include:

With our coal and transportation assets we:

control over 9.000 railcarsown and/or operate over 2,900 hopper barges and 80 towboatsoperate one active coal-handling terminal with 20 millions tons of capacity

SIGNIFICANT PRESENCE THROUGHOUT 

THE DOMESTIC VALUE CHAIN
7

Business Strategy

AEP’s mission is to bring comfort to our customers, support business and commerce and build strong communities. Our strategy to achieve 

our mission is to grow our core utility business at a moderate and steady rate through major investment in our current utility business 

supported and funded by innovative programs for regulatory recovery as well as develop our independent, federally regulated transmission company for the pursuit of new major interstate projects. Our objective is to be an economical, reliable and safe provider of electric energy to the markets that we serve. Our plan entails designing, building, improving and operating low cost, environmentally-compliant, efficient sources of power and maximizing the volumes of power delivered from these facilities. We intend to maintain and enhance our 

position as a safe and reliable provider of electric energy by making significant investments in environmental and reliability upgrades. We 

will seek to recover the cost of our new utility investments in a manner that results in reasonable rates for our customers while providing a fair return for our shareholders through a stable stream of cash flows, enabling us to pay dependable, competitive dividends. We operate 

our generating assets to maximize our productivity and profitability after meeting our native load requirements.

Company Strategy

 Continue to invest in our core utility business to enable future earnings growth while 

improving both our earned and allowed ROEs across all operating companies

 Optimize the regulatory outcome for all operating companies Maximize the output of our generation fleet and optimize our off-system sales Continue to develop our transmission opportunities Continue active involvement in climate change policy

CONTINUED COMMITMENT TO OUR CORE UTILITY MISSION: BRING 

REASONABLY PRICED ELECTRIC SERVICE TO OUR CUSTOMERS, 

THEREBY STRENGTHENING OUR COMMUNITIES AND REWARDING 

OUR INVESTORS

Our Focus

Deliver value to our investors
8

AEP Service Territory

AEP EAST OPERATING COMPANIES

Appalachian Power CompanyIndiana Michigan Power CompanyKingsport Power CompanyKentucky Power CompanyWheeling Power Company

Columbus Southern Power CompanyOhio Power Company

EAST REGULATED UTILITIES AEP OHIO
9

AEP Service Territory

AEP WEST OPERATING COMPANIES

Public Service Company of OklahomaSouthwestern Electric Power Company

Texas Central CompanyTexas North Company

WEST REGULATED UTILITIES AEP TEXAS

Texas North CompanyTexas Central Company
10

Utility Operations - Load

3 Yr. Compound Annual Industrial 

Load Growth at 3.79%

3 Yr. Compound Annual Commercial 

Load Growth at 2.91%

Note: Figures do not include Texas Retail and Miscellaneous Other

3 Yr. Compound Annual 

Residential Load Growth at 2.42% 45,770

48,720 47,222 49,176

50,00045,00040,00035,00030,000

Millions of 

kWh

2004 2005 2006 2007

Residential

51,484

53,217 53,914

57,566

60,00057,50055,00052,50050,00047,500

Millions of 

kWh

2004 2005 2006 2007

Industrial

37,203 38,605 38,579

40,545

45,00040,00035,00030,00025,000

Millions of 

kWh

2004 2005 2006 2007

Commercial
11

TX

OK IN

VA

2007 Retail Revenue 

PERCENTAGE OF 

AEP SYSTEM RETAIL REVENUES Retail Revenue Composition by Customer Class**

CUSTOMER PROFILE

AEP’S SERVICE TERRITORY ENCOMPASSES 

APPROXIMATELY 5 MILLION CUSTOMERS IN 11 STATES

Source: Form 10-K*Note: Retail electric service in the ERCOT area of Texas is provided to most customers through unaffiliated REPs with TCC and TNC providing only regulated delivery services. Retail electric service in the SPP area of Texas is provided by SWEPCo and an affiliated REP.**Note: Figures do not include Other Retail Sales

13%33%

9%

9%

1%2%2%4%4%5%8%

10%

27.9%30.4%41.7%

Industrial 27.9%Commercial 30.4%Residential 41.7%

Tennessee 1%Michigan 2%Arkansas 2%Kentucky 4%Louisiana 4%Texas SPP 5%Texas ERCOT 8%Virginia 9%Indiana 9%West Virginia 10%Oklahoma 13%Ohio 33%
12

Utility Operations

GenerationAEP has approximately 39,000 megawatts of generating capacity in 3 RTOs. AEP owns all or 

portions of 60 major generating plants, which include coal/lignite, natural gas, nuclear, wind projects and hydroelectric facilities. AEP operates generating capacity in its internal power pool under an economic dispatch 

system1. AEP’s power pool’s competitive, largely coal-based production costs are among the 

lowest in the nation. AEP’s power production costs are also kept relatively low by its reliance primarily on fossil fuel (gas and coal), with only a small overall nuclear dependence.

1 Economic dispatch of a generating system utilizes the lowest-cost generating units to meet electric demand at any point in time.
13

Coal/Lignite

69%

Nat. Gas/Oil

20%

Nuclear

6%

Pumped Storage/ 

Hydro/Wind

5%

AEP’s Generation Fleet

38,721* MW Capacity

Domestic Generation Fleet

Operating Statistics NERC Regional Presence

200520062007

Equivalent Capacity 

Factor

Equivalent 

Availability Factor

59.54% 81.84%60.06% 82.62%63.18% 84.76%

5% ERCOT

23% SPP72% RFC 

* Includes 270 MW of mothballed/decommissioned generating capacity.
14

Transmission Line Circuit Miles Detail

Operating Company Level (Circuit Miles)

State Level (Circuit Miles)

Note: Transmission line circuit miles are current as of 12/31/07

State 765kV 500kV 345kV 230kV 161kV 138kV 115kV 88kV 69kV 46kV 40kV 34.5kV 23kV Total

0

Arkansas 0 0 28 0 228 168 42 0 461 0 0 0 0 927Indiana 600 0 1,380 0 0 1,426 0 0 412 0 0 591 0 4,409Kentucky 258 0 8 0 46 320 0 0 544 55 0 3 0 1,234Louisiana 0 0 105 0 0 248 0 0 233 0 0 0 0 586Michigan 16 0 234 0 0 239 0 0 299 0 0 148 0 936Ohio 509 0 1,793 0 0 3,358 0 0 2,636 0 59 365 225 8,945Oklahoma 0 0 625 34 8 2,174 10 0 812 0 0 0 0 3,663Tennessee 0 0 0 91 0 154 0 0 3 0 0 27 0 275Texas 0 0 1,345 0 0 4,793 14 0 5,151 0 0 0 0 11,303W. Virginia 384 17 323 0 0 1,602 0 23 457 739 0 89 0 3,634Virginia 349 96 69 15 0 1,720 0 0 709 48 0 141 0 3,147Total 2,116 113 5,910 140 282 16,202 66 23 11,717 842 59 1,364 225 39,059

Operating Company 765kV 500kV 345kV 230kV 161kV 138kV 115kV 88kV 69kV 46kV 40kV 34.5kV 23kV TotalAPCo 734 97 383 106 0 3,302 0 23 1,079 787 0 230 0 6,741CSP 0 0 884 0 0 893 0 0 467 0 59 0 113 2,416I&M 615 0 1,614 0 0 1,665 0 0 711 0 0 739 0 5,344

KGPCo 0 0 0 0 0 0 0 0 3 0 0 27 0 30KPCo 258 0 8 0 46 320 0 0 544 55 0 3 0 1,234

OPCo 509 0 909 0 0 2,464 0 0 2,169 0 0 365 112 6,528

PSO 0 0 579 34 8 2,149 10 0 812 0 0 0 0 3,592

SWEPCo 0 0 660 0 228 1,195 42 0 1,405 0 0 0 0 3,530TCC 0 0 641 0 0 2,453 0 0 1,740 0 0 0 0 4,834TNC 0 0 223 0 0 1,586 14 0 2,699 0 0 0 0 4,522WPCo 0 16 9 0 0 175 0 0 88 0 0 0 0 288

Total 2,116 113 5,910 140 282 16,202 66 23 11,717 842 59 1,364 225 39,059
15

Distribution Line Detail

Note: Distribution line circuit miles are current as of 12/31/2007

The Texas Panhandle Area was transferred from Texas North (Abilene District) to SWEPCO (Texarkana District) during 2007.Musser Companies takeover included in APCO WVA mileage numbers.

By

Operating

By State Line Miles* Company Line Miles*

Tennessee 1,522 | KGPCO 1,522

Virginia 30,005 | KYPCO 9,848

W. Virginia 21,339 | APCO 49,860

Kentucky 9,848 | OPCO 26,396

Ohio 45,110 | CSP 18,714Michigan 5,247 | I&M 20,089Indiana 14,842 | WPC 1,484

Texas 51,320 | TCC 29,038

Oklahoma 21,622 | TNC 13,772

Arkansas 4,442 | PSO 21,622

Louisiana 7,484 | SWEPCO 20,436

Total 212,781 Total 212,781

* Includes approximately 28,800 miles of underground circuit miles
16

Utility Operations

PROPERTY, PLANT & EQUIPMENT DETAIL ($ MILLIONS)

Property Plant and Equipment Original Cost AEP Accumulated D&A Net Utility Plant

Electric:

Production 20,948 $ 9,200 $ 11,748 $ 

Transmission 7,734 2,417 5,317

Distribution 12,561 3,332 9,229

Other (including coal mining & 

nuclear fuel) 3,633 1,708 1,925

Work in Progress 3,516 (54) 3,570

Total 48,392 $ 16,603 $ 31,789 $ 

Source: Company information as of 9/30/08
Operating Company

Overview Regulation

Generation &

Environmental Company Overview Coal
17

Operating Company 

Overview

Fall EEI 2008

• Organizational Structure

• AEP East Regional Utilities

• AEP West Regional Utilities

18

Organizational Structure

Mike Carl Bob Brian

Joe Dana Helen Pablo

Venita

Tim Stuart

COO

Carl English

President

AEP Utilities

Bob Powers

EVP

AEP Utilities East

Brian Tierney

EVP

AEP Utilities West

Venita McCellon-Allen

President

Ohio

Joe Hamrock

President

Appalachian Power

Dana Waldo

President

Indiana Michigan Power

Helen Murray

President

Kentucky Power

Tim Mosher

President

Texas

Pablo Vegas

President

SWEPCO

Paul Chodak III

President

Public Service of Oklahoma

Stuart Solomon

Senior management close to customers and 

regulators

CEO

Mike Morris

Paul
19

AEP East Regional Utilities
20

Appalachian Power

Appalachian Power Company (APCo) (organized in Virginia in 1926) is engaged in the generation, 

transmission and distribution of electric power to approximately

956,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. APCo covers a service territory of 19,049 square miles, and at December 31, 2007, APCo and its wholly owned subsidiaries had 2,497 employees. Among theprincipal industries served by APCo are coal mining, primary metals, chemicals and textile mill products. In addition to its AEP System interconnections, APCo also is interconnected with the followingunaffiliated utility companies: Carolina Power & Light Company, Duke Energy Corporation and Virginia Electric and Power Company.APCo has several points of interconnection with TVA and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems. APCo is a member of PJM.

PRINCIPAL INDUSTRIES SERVED:

Coal mining 

Primary metals 

Chemicals 

Textile mill products 

Paper products

President and Chief Operating Officer: Dana Waldo

Total Customers at 12/31/07:• Residential 815,000• Commercial 130,000• Industrial 4,000• Other 7,000 

Total 956,000

Generating Capacity 6,290 MWGenerating Capacity by Fuel Mix:

• Coal: 80.9%• Hydro/Pump: 10.8% • Nat Gas: 8.3%

Transmission Miles 6,741Distribution Miles 49,860
21

Debt Equity Total Debt Equity Total Debt Equity Total

Capitalization Per Balance Sheet 2,345,511 1,821,485 4,166,996 2,633,639 2,053,937 4,687,576 3,122,556 2,099,784 5,222,340

% of Capitalization Per Balance Sheet 56.3% 43.7% 100.0% 56.2% 43.8% 100.0% 59.8% 40.2% 100.0%Adjusted Capitalization 2,345,511 1,821,485 4,166,996 2,633,639 2,053,937 4,687,576 3,133,657 2,099,784 5,233,441

% of Adjusted Capitalization 56.3% 43.7% 100.0% 56.2% 43.8% 100.0% 59.9% 40.1% 100.0%FFO Interest Coverage 3.7 3.9 3.1

FFO Total Debt 12.4% 14.4% 12%

CAPITAL STRUCTURE (in thousands)

CAPITAL STRUCTURE 2005 2006 2007

Revenue 2,607,000 $ 

% of AEP Retail 18%Net Income 54,000 $ 

Capital Expenditure 746,000 $ 

2007 Financial Data * (in thousands)

As of 9/30/08

Total Assets 8,161,499 $ 

Net Plant Assets 6,495,352 $ Cash 1,987 $ 

2008 Asset Data ** (in thousands)

Appalachian Power

Sources: * 2007 Form 10-K

** 3Q08 Form 10-Q (unaudited)

Note: Capital Expenditure amounts exclude AFUDC
22

Nat Gas 516 Ceredo, West Virginia Ceredo #1,2,3,4,5,6

Hydro 15 Winfield, West Virginia Winfield #1,2,3

Pump 586 Penhook, Virginia Smith Mountain #1,2,3,4,5

Hydro 6 Lynchburg, Virginia Reusens #1,2,3,4,5

Hydro 1 Roanoke, Virginia Niagara #1,2

Hydro 9 Leesville, Virginia Leesville #1,2

Coal 335 Glen Lyn, Virginia Glen Lyn #1,2Coal 705 Carbo, Virginia Clinch River #1,2,3

Hydro 28 Radford, Virginia Claytor #1,2,3,4Hydro 11 Marmet, West Virginia Marmet #1,2,3

Coal 400 Glasgow, West Virginia Kanawha River #1,2

Hydro 12 Montgomery, West Virginia London #1,2,3

Coal 300 New Haven, West Virginia Philip Sporn #1,3Coal 1,320 New Haven, West Virginia Mountaineer #1Coal 2,033 St. Albans, West Virginia John E. Amos #1,2 (APCo owns 1/3 of Unit 3)

Hydro 8 Byllesby, Virginia Byllesby #1,2,3,4

Hydro 5 Ivanhoe, Virginia Buck #1,2,3

Fuel Nominal Megawatt Capacity Location Name

Appalachian Power Plants (Winter Capacity)

32,344,23912,878,704

Three Year Average

12,828,218 12,619,910 13,187,986 Coal Consumption (tons burned)32,588,773 31,494,581 32,949,364 MWh Produced

2007 2006 2005 Production Stat

APCo Generation Production Statistics – 2005 - 2007

Operating Information

2007 retail electric sales in megawatt-hours 33,875,411 2007 firm wholesale sales in megawatt-hours 3,435,670

Average cost per kilowatt-hour (residential) 6.36 cents 2007 System Peak – February 6 8,003 MW

Appalachian Power
23

MAJOR CUSTOMERS:

Century Aluminum of WV, Inc. (WV)

Felman Production (WV)

Roanoke Electric Steel Corporation (VA)

Georgia-Pacific Corporation (VA)

Alcan Rolled Products (WV)

Greif Brothers Corporation (VA)

West Virginia Alloys, Inc. (WV)

Steel of West Virginia (WV)

Goodyear Tire and Rubber (VA)

CNX Gas Company (VA)

(data for year ended December 2007)

APPALACHIAN AREA INVESTOR OWNED UTILITIES *

TYPICAL BILL COMPARISON **

29,963 Kentucky 

Utilities

22,282 Potomac

509,315 APCo

2,211,200 Dominion Virginia

98,574 Allegheny

Customers Virginia

Customers Tennessee

46,208 APCo

500,051 Allegheny

435,765 APCo

Customers West Virginia

• Top 10 Customers = 50% of industrial sales• Metropolitan areas account for 34% of ultimate sales• 110 persons per square mile (U.S. = 85)

(data for 12 months ended December 2007)

** Typical bills are displayed in $/month, based on 1,000 kWh of residential 

usage. Billing amounts sourced from the EEI 2008 Typical Bills and Average Rates Report as of January 1, 2008.

122.92 Potomac

88.69 Dominion Virginia 72.52 Allegheny

71.96 APCo 64.55 AEP – Wheeling

68.72 Old Dominion Power 

(Kentucky Utilities)

64.55 APCo

$/month Virginia $/month West Virginia

Appalachian Power

* Customer counts are as of December 31, 2006 and were sourced from table 10 

at http://www.eia.doe.gov/cneaf/electricity/esr/esr_sum.html
24

Columbus Southern Power Company (CSPCo) (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, transmission and distribution of electric power to approximately 746,000 retail customers in Ohio, and in supplying and marketing electric power at wholesale to other electric utilities, municipalities and other market participants. CSPCo covers a service territory of 3,701 miles and at December 31, 2007, CSPCo had 1,265 employees. CSPCo’s service area is comprised of two areas in Ohio, which include portions of twenty-five counties. One area includes the City of Columbus and the other is a predominantly rural area in south central Ohio. In addition to its AEP System interconnections, CSPCo also is interconnected with the following unaffiliated utility companies: Duke Energy Ohio, DP&L and Ohio Edison Company. CSPCo is President and Chief Operating Officer: a member of PJM. 

Joe Hamrock

Total Customers at 12/31/07:• Residential 666,000 • Commercial 77,000• Industrial 3,000

Total 746,000

Generating Capacity 3,701 MWGenerating Capacity by Fuel Mix:

• Coal 63.4%

• Natural Gas 36.6%

Transmission Miles 2,416Distribution Miles 18,714

PRINCIPAL INDUSTRIES SERVED:

Food processing 

Chemicals

Primary metals

Fabricated metals

Rubber and plastic products

Columbus Southern Power
25

Debt Equity Total Debt Equity Total Debt Equity Total

Capitalization Per Balance Sheet 1,214,529 981,546 2,196,075 1,198,018 1,056,017 2,254,035 1,393,423 1,164,277 2,557,700

% of Capitalization Per Balance Sheet 55.3% 44.7% 100.0% 53.1% 46.9% 100.0% 54.5% 45.5% 100.0%Adjusted Capitalization 1,214,529 981,546 2,196,075 1,198,018 1,056,017 2,254,035 1,401,551 1,164,277 2,565,828

% of Adjusted Capitalization 55.3% 44.7% 100.0% 53.1% 46.9% 100.0% 54.6% 45.4% 100.0%FFO Interest Coverage 5.8 6.2 5.9

FFO Total Debt 24.3% 28.8% 26.9%

2005 2006 2007

CAPITAL STRUCTURE (in thousands)

CAPITAL STRUCTURE

Revenue 2,043,000 $ 

% of AEP Retail 16%

Net Income 258,000 $ 

Capital Expenditure 338,000 $ 

2007 Financial Data * (in thousands)

As of 9/30/08

Total Assets 3,949,104 $ 

Net Plant Assets 3,262,005 $ Cash 1,956 $ 

2008 Asset Data ** (in thousands)

Columbus Southern Power

Sources: * 2007 Form 10-K

** 3Q08 Form 10-Q (unaudited)

Note: Capital Expenditure amounts exclude AFUDC
26

Operating Information

2007 retail sales in megawatt-hours 22,008,6072007 firm wholesale sales in megawatt-hours 0

Average cost per kilowatt-hour (residential) 8.81 cents2007 System Peak – August 8 4,723 MW

Oil 3 Aberdeen, Ohio J. M. Stuart #1,2,3,4 (Units co-owned by DP&L, Duke, CSP 26%)

Nat Gas 507 Mount Sterling, Ohio Darby # 1,2,3,4,5,6

Coal 604 Aberdeen, Ohio J. M. Stuart #1,2,3,4 (Units co-owned by DP&L, Duke, CSP 26%)

Coal 1,254 Conesville, Ohio Conesville #1,2,3,4 (Unit #4 co-owned by DP&L, Duke, CSP 43.5%) Coal 100 Lockbourne, Ohio Picway #1Coal 330 Moscow, Ohio Wm. H. Zimmer #1 (Co-owned by DP&L, Duke, CSP 25.4%)

Nat Gas 850 Washington County, Ohio Waterford # 1,2,3,4

Coal 53 New Richmond, Ohio Beckjord #6 (Co-owned by DP&L, Duke, CSP 12.5%)

Fuel Nominal Megawatt Capacity Location Name

Columbus Southern Plants (Winter Capacity)

6,109,649

14,562,257

Three Year Average

6,327,803 5,953,084 6,048,060 Coal Consumption (tons burned)

15,514,495 14,134,232 14,038,045 MWh Produced

2007 2006 2005 Production Stat

Columbus Southern Generation Production Statistics – 2005 – 2007

Columbus Southern Power
27

OHIO INVESTOR OWNED UTILITIES * TYPICAL BILL COMPARISON ****

513,074 DP&L

1,449,636 AEP Ohio **

1,820,036 First Energy ***

670,135 Duke Energy Ohio 

Customers Ohio

MAJOR CUSTOMERS:

Ormet Aluminum

Eramet Marietta, Inc.

Kraton Polymers

E I duPont de Nemours HQ

Glatfelter Company

Anheuser-Busch, Inc.

Griffin Wheel Company, Inc.

(data for year ended December 2007)

• Top 10 customers = 59% of industrial sales• Metropolitan areas account for 86% of ultimate sales• 238 persons per square mile (U.S. = 85)

(data for 12 months ended December 2007)

  Typical bills are displayed in $/month, based on 

1,000 kWh of residential usage. Billing amounts sourced from the EEI 2008 Typical Bills and Average Rates Report as of January 1, 2008. Ohio rates represent POLR bundled residential rates.

116.35 FE (Ohio Edison)109.90 FE (CEI)

98.54 DP&L

125.27 FE (Toledo Edison)107.25 Duke Energy Ohio 

93.78 AEP (CSP)80.61 AEP (OPCo)

$/month Ohio

**  AEP Ohio - CSPCo = 739,424

OPCo = 710,212

*** First Energy - Toledo Edison = 265,028

CEI = 702,968

Ohio Edison = 852,040

Columbus Southern Power

* Customer counts are as of December 31, 2006 and were sourced from table 10 

at http://www.eia.doe.gov/cneaf/electricity/esr/esr_sum.html
28

Indiana Michigan Power Company (I&M) (organized in Indiana in 1925) is engaged in the generation, transmission and distribution of electric power to approximately583,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants. I&M has a service territory of 4,578 square miles and at December 31, 2007, I&M had 2,687 employees. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana. In addition to its AEP System interconnections, I&M also is interconnected with the following unaffiliated utility companies: Central Illinois Public Service Company, Duke Energy Ohio, Commonwealth Edison Company, Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, Duke Energy Indiana and

President and Chief Operating Officer: 

Richmond Power & Light Company. I&M is a member of PJM.

Helen Murray

PRINCIPAL INDUSTRIES SERVED:

Primary metals

Transportation equipment

Fabricated metal products

Rubber and miscellaneous plastic products

Chemicals and allied products 

Total Customers at 12/31/07:• Residential 508,000 

• Commercial 68,000• Industrial 5,000• Other 2,000

Total 583,000

Generating Capacity 5,821 MWGenerating Capacity by Fuel Mix:

• Coal: 51.1%• Nuclear: 48.6% • Hydro: 0.3%

Transmission Miles 5,344Distribution Miles 20,089

Indiana Michigan Power
29

Debt Equity Total Debt Equity Total Debt Equity Total

Capitalization Per Balance Sheet 1,538,642 1,228,176 2,766,818 1,646,308 1,297,521 2,943,829 1,612,491 1,393,779 3,006,270

% of Capitalization Per Balance Sheet 55.6% 44.4% 100.0% 55.9% 44.1% 100.0% 53.6% 46.4% 100.0%Adjusted Capitalization 1,909,337 1,228,176 3,137,513 1,991,717 1,297,521 3,289,238 2,049,215 1,393,779 3,442,994

% of Adjusted Capitalization 60.9% 39.1% 100.0% 60.6% 39.4% 100.0% 59.5% 40.5% 100.0%FFO Interest Coverage 4.7 4.8 4.8FFO Total Debt 22.8% 23.9% 26.1%

CAPITAL STRUCTURE (in thousands)

CAPITAL STRUCTURE 2005 2006 2007

Revenue 2,043,000 $ 

% of AEP Retail 11%Net Income 137,000 $ 

Capital Expenditure 295,000 $ 

2007 Financial Data * (in thousands)

As of 9/30/08

Total Assets 5,935,699 $ 

Net Plant Assets 3,702,117 $ Cash 1,328 $ 

2008 Asset Data ** (in thousands)

Indiana Michigan Power

Sources: * 2007 Form 10-K

** 3Q08 Form 10-Q (unaudited)

Note: Capital Expenditure amounts exclude AFUDC
30

Operating Information

2007 retail electric sales in megawatt-hours 19,552,1262007 firm wholesale sales in megawatt-hours 3,555,874 Average cost per kilowatt-hour (residential) 6.83 cents2007 System Peak – August 7 4,528 MW

7,455,181 7,406,506 7,947,666 7,011,370 Coal Consumption (tons burned)

31,696,956 31,604,874 31,950,768 31,535,226 MWh Produced

Three-Year Avg. 2007 2006 2005 Production Stat

I&M Generation Production Statistics – 2005 – 2007

Indiana Michigan Power

Nuclear 2,191 Bridgman, Michigan Donald C Cook #1,2

Hydro 4 Mishawaka, Indiana Twin Branch #1,2,3,4,5,6Hydro 5 Berrien Springs, Michigan Berrien Springs #1,2,3,4,5,6,7,8,9,10,11,12

Coal 2,620 Rockport, Indiana Rockport #1,2 (includes AEG)

Hydro 1 Mottville, Michigan Mottville #1,2,3,4Hydro 1 Constantine, Michigan Constantine #1,2,3,4Hydro 2 Buchanan, Michigan Buchanan #1,2,3,4,5,6,7,8,9,10

Coal 995 Lawrenceburg, Indiana Tanners Creek #1,2,3,4

Hydro 2 Elkhart, Indiana Elkhart #1,2,3

Fuel Nominal Megawatt Capacity Location Name

Indiana Michigan Power Plants (Winter Capacity)
31

INDIANA & MICHIGAN INVESTOR OWNED UTILITIES * TYPICAL BILL COMPARISON **

1,779,1842,156,214

** Typical bills are displayed in $/month, based on 1,000 kWh of residential 

usage. Billing amounts sourced from the EEI 2008 Typical Bills and Average Rates Report as of January 1, 2008.

• Top 10 Customers = 47% of industrial sales• Metropolitan areas account for 68% of ultimate sales• 204 persons per square mile (U.S. = 85)(data for 12 months ended December 2007)

MAJOR CUSTOMERS:

Steel Dynamics Inc. (IN)

American Axle and Mfg. Co, Inc. (MI)

Air Products & Chemicals, Inc. (IN)

Boc Gases (IN)

Saint Gobain Corporation USA (IN)

Whirlpool Corporation (MI)

New Energy Corp (IN)

Dock Foundry (MI)

White Pigeon Paper Company (MI)

IN TEK (IN)

The Minute Maid Company (MI)

(data for year ended December 2007)

116.10 SIGECo

113.12 Detroit Edison 89.19 Duke Energy Indiana 

101.79 Consumers Energy 73.37 IP & L

66.09 I & M 71.46 I & M

$/month Michigan $/month Indiana

Indiana Michigan Power

* Customer counts are as of December 31, 2006 and were sourced from table 10 

at http://www.eia.doe.gov/cneaf/electricity/esr/esr_sum.html

450,819 NIPSCO145,726 SIGECo766,165 Duke Energy Indiana 466,833 IP & L

454,345 I & M

Customers Indiana

2,166,478 Detroit Edison1,792,469 Consumers Energy

126,546 I & M

Customers Michigan
32

Kentucky Power

Kentucky Power Company (KPCo) (organized in Kentucky in 1919) is engaged in the generation, 

transmission and distribution of electric power to approximately

176,000 retail customers in an area in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. KPCo encompasses a service territory of 4,813 square miles and at December 31, 2007, KPCo had 471 employees. In addition to its AEP System interconnections, KPCo also is interconnected with the following unaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc. KPCo is also interconnected with TVA. KPCo is amember of PJM.

President and Chief Operating Officer: Tim Mosher

Total Customers at 12/31/07:• Residential 144,000 

• Commercial 30,000• Industrial 1,500• Other 500

Total 176,000

Generating Capacity 1,060 MWGenerating Capacity by Fuel Mix:

• Coal: 100%

Transmission Miles 1,234Distribution Miles 9,848

PRINCIPAL INDUSTRIES SERVED:

Petroleum refining

Coal mining

Primary metals

Chemicals

Electric/gas/sanitary services
33

Debt Equity Total Debt Equity Total Debt Equity Total

Capitalization Per Balance Sheet 493,030 347,841 840,871 477,604 369,651 847,255 467,526 386,969 854,495

% of Capitalization Per Balance Sheet 58.6% 41.4% 100.0% 56.4% 43.6% 100.0% 54.7% 45.3% 100.0%Adjusted Capitalization 493,030 347,841 840,871 477,604 369,651 847,255 469,770 386,969 856,739

% of Adjusted Capitalization 58.6% 41.4% 100.0% 56.4% 43.6% 100.0% 54.8% 45.2% 100.0%FFO Interest Coverage 3.4 3.9 3.8

FFO Total Debt 14.0% 17.7% 17.3%

2005 2006 2007

CAPITAL STRUCTURE (in thousands)

CAPITAL STRUCTURE

Revenue 588,000 $ 

% of AEP Retail 4%

Net Income 32,500 $ 

Capital Expenditure 68,000 $ 

2007 Financial Data * (in thousands)

As of 9/30/08

Total Assets 1,385,672 $ 

Net Plant Assets 1,096,852 $ Cash 455 $ 

2008 Asset Data ** (in thousands)

Kentucky Power

Sources: * 2007 Annual Report

** 3Q08 Financial Statements (unaudited)

Note: Capital Expenditure amounts exclude AFUDC
34

Operating Information

2007 retail electric sales in megawatt-hours 7,114,5062007 firm wholesale sales in megawatt-hours 100,2492007 average cost per kilowatt-hour (residential) 6.71 cents2007 System Peak – February 6 1,808 MW

Coal 1,060 Louisa, Kentucky Big Sandy #1,2

Fuel Nominal Megawatt Capacity Location Name

Kentucky Power Plants (Winter Capacity)

7,350,1172,910,362

Three-Year Average

2,950,296 2,854,537 2,926,253 Coal Consumption (tons burned)7,533,223 7,171,505 7,345,624 MWh Produced

2007 2006 2005 Production Stat

Kentucky Power Generation Production Statistics – 2005-2007

Kentucky Power
35

KENTUCKY INVESTOR OWNED UTILITIES * TYPICAL BILL COMPARISON **

397,331 LG & E497,939 Kentucky Utilities

175,572 KPCo

Customers Kentucky

MAJOR CUSTOMERS:

Catlettsburg Refining LLC

AK Steel Holding Corporation

Sidney Coal Company, Inc.

Air Products & Chemicals, Inc.

KES Acquisition Company LLC

McCoy Elkhorn Coal Corporation

Blue Diamond Coal Company

Perry County Coal Corporation

Consol of Kentucky, Inc.

Czar Coal Corporation

(data for year ended December 2007)

• Top 10 customers = 63% of industrial sales• Metropolitan areas account for 41% of ultimate sales• 68 persons per square mile (U.S. = 85)(data for 12 months ended December 2007)

** Typical bills are displayed in $/month, 

based on 1,000 kWh of residential usage. Billing amounts sourced from the EEI 2008 Typical Bills and Average Rates Report as of January 1, 2008.

74.53 LG&E

67.89 KPCo

77.69 Duke Energy Kentucky73.67 Kentucky Utilities

$/month Kentucky

* Customer counts are as of December 31, 2006 and were sourced from table 10 

at http://www.eia.doe.gov/cneaf/electricity/esr/esr_sum.html

Kentucky Power
36

Ohio Power Company (OPCo) (organized in Ohio in 1907 and re-incorporated in 1924) is engaged in the generation, transmission and distribution of electric power to approximately 712,000 retail customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. OPCO covers a service territory of 6,675 miles and at December 31, 2007, OPCo had 2,351 employees. In addition to its AEP System interconnections, OPCo also is interconnected with the following unaffiliated utility companies: Duke Energy Ohio, The Cleveland Electric Illuminating Company, DP&L, Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power Company. OPCo is a member of PJM.

PRINCIPAL INDUSTRIES SERVED:

Primary metals

Rubber and plastic products

Stone, clay and glass products

Petroleum refining

Chemicals

President and Chief Operating Officer: Joe Hamrock

Total Customers at 12/31/07:• Residential 610,000 

• Commercial 92,000• Industrial 7,000• Other 3,000

Total 712,000

Generating Capacity 8,478 MWGenerating Capacity by Fuel Mix:

• Coal: 99.7%• Hydro: 0.3% 

Transmission Miles 6,528Distribution Miles 26,396

Ohio Power
37

Debt Equity Total Debt Equity Total Debt Equity Total

Capitalization Per Balance Sheet 2,291,409 1,784,586 4,075,995 2,600,050 2,024,972 4,625,022 2,951,847 2,307,644 5,259,491

% of Capitalization Per Balance Sheet 56.2% 43.8% 100.0% 56.2% 43.8% 100.0% 56.1% 43.9% 100.0%Adjusted Capitalization 2,291,409 1,784,586 4,075,995 2,600,050 2,024,972 4,625,022 2,980,924 2,307,644 5,288,568

% of Adjusted Capitalization 56.2% 43.8% 100.0% 56.2% 43.8% 100.0% 56.4% 43.6% 100.0%FFO Interest Coverage 6.2 6.2 4.5FFO Total Debt 23.8% 19.7% 19.1%

CAPITAL STRUCTURE (in thousands)

CAPITAL STRUCTURE 2005 2006 2007

Revenue 2,814,000 $ 

% of AEP Retail 16%Net Income 268,000 $ 

Capital Expenditure 933,000 $ 

2007 Financial Data * (in thousands)

As of 9/30/08

Total Assets 7,684,833 $ 

Net Plant Assets 6,459,196 $ Cash 9,088 $ 

2008 Asset Data ** (in thousands)

Ohio Power

Sources: * 2007 Form 10-K

** 3Q08 Form 10-Q (unaudited)

Note: Capital Expenditure amounts exclude AFUDC
38

Operating Information

2007 retail sales in megawatt-hours 27,727,742

2007 firm wholesale sales in megawatt-hours 2,293,855Average cost per kilowatt-hour (residential) 7.72 cents2007 System Peak – August 23 5,485 MW

Hydro 26 Racine, Ohio Racine #1,2

Coal 750 New Haven, West Virginia Phillip Sporn # 2,4,5

Coal 580 Brilliant, Ohio Cardinal #1 (Two other units owned by Buckeye Power)

Coal 630 Moundsville, West Virginia Kammer #1,2,3

Coal 867 St. Albans, West Virginia John E. Amos #3 (2/3; 1/3 owned by APCo)Coal 1,425 Beverly, Ohio Muskingum River #1,2,3,4,5Coal 1,560 Moundsville, West Virginia Mitchell #1,2

Coal 2,640 Cheshire, Ohio Gen. JM Gavin #1,2

Fuel Nominal Megawatt Capacity Location Name

Ohio Power Plants (Winter Capacity)

51,859,13920,242,539

Three Year Average

21,234,430 19,111,071 20,382,116 Coal Consumption (tons burned)54,155,697 49,341,134 52,080,585 MWh Produced

2007 2006 2005 Production Stat

Ohio Power Generation Production Statistics – 2005–2007

Ohio Power
39

OHIO INVESTOR OWNED UTILITIES * TYPICAL BILL COMPARISON ****

MAJOR CUSTOMERS:

Wheeling-Pittsburgh Steel Corp.

The Timken Company

Republic Engineered Products, LLC

Ormet Primary Aluminum Corp.

Globe Metallurgical, Inc.

Premcor Refining Group, Inc.

Linde Glass, LLC

Owens Corning Fiberglass Corp.

Marathon Ashland Petroleum, LLC

Aristech Chemical Corp.

(data for year ended December 2007)

• Top 10 customers = 50% of industrial sales• Metropolitan areas account for 60% of ultimate sales• 136 persons per square mile (U.S. = 85) 

(data for 12 months ended December 2007)

  Typical bills are displayed in $/month, based on 

1,000 kWh of residential usage. Billing amounts sourced from the EEI 2008 Typical Bills and Average Rates Report as of January 1, 2008. Ohio rates represent POLR bundled residential rates.

513,074 DP&L

1,449,636 AEP Ohio ** 

1,820,036 First Energy ***

670,135 Duke Energy Ohio

Customers Ohio

Ohio Power

* Customer counts are as of December 31, 2006 and were sourced from table 10 

at http://www.eia.doe.gov/cneaf/electricity/esr/esr_sum.html

** AEP Ohio - CSPCo = 739,424

OPCo = 710,212

***First Energy - Toledo Edison = 265,028

CEI = 702,968

Ohio Edison = 852,040

116.35 FE (Ohio Edison)109.90 FE (CEI)

98.54 DP&L

125.27 FE (Toledo Edison)107.25 Duke Energy Ohio

93.78 AEP (CSP)80.61 AEP (OPCo)

$/month Ohio
40

AEP West Regional Utilities
41

Public Service Company of Oklahoma

Public Service Company of Oklahoma (PSO) (organized in Oklahoma in 1913) is engaged in the generation, transmission and distribution of electric power to approximately 525,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies,municipalities, rural electric cooperatives and other market participants. PSO has a service territory of 30,000 square miles and at December 31, 2007, PSO had 1,255 employees. In addition to its AEP System interconnections, PSO also is interconnected with Ameren Corporation, Empire District Electric Co., Oklahoma Gas & Electric Co., Southwestern Public Service Co. and Westar 

President and Chief Operating Officer:

Energy, Inc. PSO is a member of SPP.

Stuart Solomon

PRINCIPAL INDUSTRIES SERVED:

Oil and gas extraction

Paper products

Stone, clay and glass products

Primary metals

Transportation equipment

Total Customers at 12/31/07:• Residential 451,000 • Commercial 59,000• Industrial 7,000• Other 8,000

Total 525,000

Generating Capacity 4,581 MWGenerating Capacity by Fuel Mix:

• Coal: 22.2%• Natural Gas: 77.2%• Oil: 0.6%

Transmission Miles 3,592Distribution Miles 21,622
42

Debt Equity Total Debt Equity Total Debt Equity Total

Capitalization Per Balance Sheet 646,954 553,859 1,200,813 746,321 590,700 1,337,021 918,316 646,160 1,564,476

% of Capitalization Per Balance Sheet 53.9% 46.1% 100.0% 55.8% 44.2% 100.0% 58.7% 41.3% 100.0%Adjusted Capitalization 646,954 553,859 1,200,813 746,321 590,700 1,337,021 922,343 646,160 1,568,503

% of Adjusted Capitalization 53.9% 46.1% 100.0% 55.8% 44.2% 100.0% 58.8% 41.2% 100.0%FFO Interest Coverage 2.8 6.0 2.6FFO Total Debt 9.5% 27.2% 9.2%

2005 2006 2007

CAPITAL STRUCTURE (thousands)

CAPITAL STRUCTURE

Revenue 1,396,000 $ 

% of AEP Retail 13%Net Loss (24,000) $ 

Capital Expenditure 315,000 $ 

2007 Financial Data * (in thousands)

As of 9/30/08

Total Assets 2,971,827 $ 

Net Plant Assets 2,430,979 $ Cash 2,244 $ 

2008 Asset Data ** (in thousands)

Sources: * 2007 Form 10-K

** 3Q08 Form 10-Q (unaudited)

Note: Capital Expenditure amounts exclude AFUDC

Public Service Company of Oklahoma
43

Nat Gas, Oil 199 Weleetka, Oklahoma Weleetka #1,2,3Nat Gas, Oil 289 Lawton, Oklahoma Comanche #1,2,3Nat Gas, Oil 627 Anadarko, Oklahoma Southwestern #1,2,3,4,5Nat Gas, Oil 943 Oologah, Oklahoma Northeastern #1,2Nat Gas, Oil 1,081 Jenks, Oklahoma Riverside #1,2,3,4

Coal 108 Vernon, Texas Oklaunion (16% ownership)

Coal, Oil 911 Oologah, Oklahoma Northeastern #3, 4

Nat Gas, Oil 423 Tulsa, Oklahoma Tulsa #1,2,3

Fuel Nominal Megawatt Capacity Location Name

Oklahoma Power Plants (Winter Capacity)

Operating Information

2007 retail electric sales in megawatt-hours 17,910,7402007 firm wholesale sales in megawatt-hours 10,536Average cost per kilowatt-hour (residential) 8.10 cents2007 System Peak – August 13 4,175 MW 

14,985,166

4,292,568

Three-Year Average

4,102,943 4,421,396 4,353,364 Coal Consumption (tons burned)

14,439,801 15,139,848 15,375,848 MWh Produced

2007 2006 2005 Production Stat

Public Service Company of Oklahoma Generation Production Statistics – 2005 - 2007

Public Service Company of Oklahoma
44

MAJOR CUSTOMERS:

Anchor Stone

Weyerhaeuser Valliant Company

Sheffield Steel

Kimberly Clark Corp.

Goodyear Tire & Rubber Company

American Airlines

Sun Refining

Terra Nitrogen

Sinclair

Explorer Pipeline Company

(data for year ended December 2007)

OKLAHOMA INVESTOR OWNED UTILITIES * TYPICAL BILL COMPARISON **

688,021 OG&E

516,875 PSO

Customers Oklahoma

• Top 10 customers = 45% of industrial sales• Metropolitan areas account for 75% of ultimate sales• 47 persons per square mile (U.S. = 85)(data for 12 months ended December 2007)

** Typical bills are displayed in $/month, 

based on 1,000 kWh of residential usage. Billing amounts sourced from the EEI 2008 Typical Bills and Average Rates Report as of January 1, 2008.

74.21 OG&E

79.43 PSO

90.89 Empire

$/month Oklahoma

* Customer counts are as of December 31, 2006 and were 

sourced from table 10 at 

http://www.eia.doe.gov/cneaf/electricity/esr/esr_sum.html

Public Service Company of Oklahoma
45

Southwestern Electric Power

Southwestern Electric Power Company (SWEPCo) (organized in Delaware in 1912) is engaged in the generation, transmission and distribution of electric power to approximately 467,000 retail customers in northeastern Texas, northwestern Louisiana and western Arkansas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. SWEPCo has a service territory of 25,000 square miles and at December 31, 2007, SWEPCo had 1,578 employees. The territory served by SWEPCo also includes several military installations, colleges, and universities. SWEPCO also owns and operates a lignite coal mining operation. In addition to its AEP System interconnections, SWEPCo is also interconnected with CLECO Corp., Empire District Electric Co., Entergy Corp. and Oklahoma Gas & Electric Co. SWEPCo is a member of SPP.

PRINCIPAL INDUSTRIES SERVED:

Oil and gas extraction

Paper products

Food processing

Primary metals

President and Chief Operating Officer: Paul Chodak III

Total Customers at 12/31/07:• Residential 394,500 • Commercial 65,000• Industrial 7,000• Other 500

Total 467,000

Generating Capacity 4,857 MWGenerating Capacity by Fuel Mix:

• Coal: 38.0%• Natural Gas: 44.7%• Lignite: 17.3%

Transmission Miles 3,530Distribution Miles 20,436
46

Debt Equity Total Debt Equity Total Debt Equity Total

Capitalization Per Balance Sheet 776,529 787,078 1,563,607 936,929 825,899 1,762,828 1,199,068 977,652 2,176,720

% of Capitalization Per Balance Sheet 49.7% 50.3% 100.0% 53.1% 46.9% 100.0% 55.1% 44.9% 100.0%Adjusted Capitalization 776,529 787,078 1,563,607 936,929 825,899 1,762,828 1,299,388 977,652 2,277,040

% of Adjusted Capitalization 49.7% 50.3% 100.0% 53.1% 46.9% 100.0% 57.1% 42.9% 100.0%FFO Interest Coverage 3.8 5.9 3.5FFO Total Debt 18.1% 28.9% 13.7%

2005 2006 2007

CAPITAL STRUCTURE (in thousands)

CAPITAL STRUCTURE

Revenue 1,483,000 $ 

% of AEP Retail 11%Net Income 66,000 $ 

Capital Expenditure 505,000 $ 

2007 Financial Data * (in thousands)

As of 9/30/08

Total Assets 4,126,456 $ Net Plant Assets 3,330,288 $ Cash 2,752 $ 

2008 Asset Data ** (in thousands)

Sources: * 2007 Form 10-K

** 3Q08 Form 10-Q (unaudited)

Note: Capital Expenditure amounts exclude AFUDC

Southwestern Electric Power
47

Operating Information

2007 retail electric sales in megawatt-hours 17,287,236

2007 firm wholesale sales in megawatt-hours 5,771,986Average cost per kilowatt-hour (residential) 7.52 cents2007 System Peak – August 14 4,924 MW

Gas 346 Tontitown, Arkansas Mattison #1,2,3,4

Gas 897 Avlinger, Texas Wilkes #1,2,3

Lignite 580 Hallsville, Texas Pirkey #1 (Own 86% and operate)

Gas 486 Longview, Texas Knox Lee #2,3,4,5

Gas 50 Lone Star, Texas Lone Star #1

Coal 1,584 Cason, Texas Welsh #1,2,3

Lignite 262 Mansfield, Louisiana Dolet Hills #1 (Own 40%; operated by CLECO)

Gas 278 Mooringsport, Louisiana Liberman #1,2,3,4

Gas 110 Shreveport, Louisiana Arsenal Hill #5

Coal 264 Gentry, Arkansas Flint Creek #1 (Own 50% and operate)

Fuel Nominal Megawatt Capacity Location Name

SWEPCO Power Plants (Winter Capacity)

19,934,20312,331,768

Three-Year Average

12,393,538 12,180,786 12,420,979 Coal/Lignite Consumption (tons burned)19,673,059 19,961,798 20,167,754 MWh Produced

2007 2006 2005 Production Stat

Southwestern Electric Power Generation Production Statistics – 2005 – 2007

Southwestern Electric Power
48

MAJOR CUSTOMERS:

Lone Star Steel Company (TX)

Big Three Industrial Gas (TX)

UOP, LLC (LA)

Domtar, Inc (AR)

International Paper Company (TX)

Pilgrim Pride Corporation (TX)

Calumet Lubricants (LA)

General Motors Corporation (LA)

Libbey Glass Inc. (LA)

Cooper Tire & Rubber Company (AR)

Letourneau (TX)

Superior Industries (AR)

Tyson Foods, Inc. (AR)

(data for year ended December 2007)

SOUTHWESTERN INVESTOR OWNED UTILITIES * TYPICAL BILL COMPARISON **

262,428 El Paso277,632 SPSCo

168,180 SWEPCo

382,202 Entergy265,556 CLECO

1,140,194 Entergy

Customers TexasCustomers Louisiana

174,213 SWEPCo

681,298 Entergy AR

111,109 SWEPCo

Customers Arkansas

• Top 10 customers = 54% of industrial sales• Metropolitan areas account for 74% of ultimate sales• 80 persons per square mile (U.S. = 85)

(data for 12 months ended December 2007)

** Typical bills are displayed in $/month, based on 1,000 kWh of residential usage. Billing amounts sourced 

from the EEI 2008 Typical Bills and Average Rates Report as of January 1, 2008.

83.55 SPSCo 86.80 Entergy LA 65.56 SWEPCo

60.11

112.96113.36

$/month Texas

SWEPCoEl PasoEntergy

115.08 CLECO104.56 Entergy Gulf St 97.02 Entergy AR101.20 Entergy NO 76.18 Empire District

66.39 SWEPCo 63.04 OG&E 

$/month Louisiana $/month Arkansas

* Customer counts are as of December 31, 2006 and were sourced from table 10 

at http://www.eia.doe.gov/cneaf/

Southwestern Electric Power

electricity/esr/esr_sum.html
49

Total Customers at 12/31/07:(Based on electric meters)

• Residential 642,000• Commercial 104,000• Industrial 5,000• Other 2,000

Total 753,000

Transmission Miles 4,834Distribution Miles 29,038

AEP Texas Central Company

AEP Texas Central Company (TCC) (organized in Texas in 1945) is engaged in the transmission and sale of power to affiliated and non-affiliated entities and the distribution of electric power to approximately 753,000 retail customers through REPs in southern Texas, and (to a limited extent) in supplying and marketing electric power at wholesale to other electric utility companies and market participants. Under the Texas Act, TCC completed its exit from the generation business through the sale of all of its generation assets. At December 31, 2007, TCC had 1,195 employees. In addition to its AEP System interconnections, TCC is a member of ERCOT.

PRINCIPAL INDUSTRIES SERVED:

Oil and gas extraction

Food processing

Petroleum refining

Chemicals

MAJOR CUSTOMERS:

Valero Energy Corporation

Koch Refinery West

Formosa

Javelina Refinery

Equistar Bay City

(data for year ended December 2007)

• Top 10 customers = 37% of industrial 

sales* ($)

• Metropolitan areas account for 78% 

ultimate sales

• 57 persons per square mile (U.S. = 85)

* Industrial % is in terms of wires revenues

(data for 12 months ended December 2007)

President and Chief Operating Officer: Pablo Vegas
50

Revenue 809,000 $ 

% of AEP Retail 7%

Net Income 59,000 $ Capital Expenditure 222,000 $ 

2007 Financial Data * (in thousands)

As of 9/30/08

Total Assets 5,131,177 $ Net Plant Assets 2,487,543 $ Cash 203 $ 

2008 Asset Data ** (in thousands)

Debt Equity Total Debt Equity Total Debt Equity Total

Capitalization Per Balance Sheet 1,935,576 953,570 2,889,146 3,015,614 411,037 3,426,651 2,937,553 465,115 3,402,668

% of Capitalization Per Balance Sheet 67.0% 33.0% 100.0% 88.0% 12.0% 100.0% 86.3% 13.7% 100.0%Adjusted Capitalization 1,269,995 953,570 2,223,565 661,806 411,037 1,072,843 665,544 465,115 1,130,659

% of Adjusted Capitalization 57.1% 42.9% 100.0% 61.7% 38.3% 100.0% 58.9% 41.1% 100.0%FFO Interest Coverage 1.4 2.0 3.7FFO to Total Debt 2.6% 13.0% 24.8%

CAPITAL STRUCTURE (in thousands)

CAPITAL STRUCTURE 2005 2006 2007

Sources: * 2007 Annual Report

** 3Q08 Financial Statements (unaudited)

Note: Capital Expenditure amounts exclude AFUDC

AEP Texas Central Company
51

AEP Texas North Company (TNC) (organized in Texas in 1927) is engaged in the generation, transmission and sale of power to affiliated and nonaffiliated entities and the distribution of electric power to approximately 184,000 retail customers through REPs in west and central Texas, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. At December 31, 2007, TNC had 373 employees. The territory served by TNC also includes several military installations and correctional facilities. In addition to its AEP System interconnections, TNC is a member of ERCOT.

PRINCIPAL INDUSTRIES SERVED:

Pipelines, except natural gas

Oil and gas extraction

Food processing

Electric equipment

Stone, clay and glass production

President and Chief Operating Officer: Pablo Vegas

Total Customers at 12/31/07:(Based on electric meters)• Residential 144,000• Commercial 30,000• Industrial 5,000• Other 5,000

Total 184,000

Generating Capacity 377 MWOklaunion Plant – Vernon, TX

(excludes 270 MW of decommissioned plants)Generating Capacity by Fuel Mix:

• Coal: 58.3%• Gas: 40.5%

• Oil: 1.2%

Transmission Miles 4,522Distribution Miles 13,772

MAJOR CUSTOMERS:

TXN

Zoltec Corporation

Tyson Foods, Inc.

Kinder Morgan

EBAA Iron

(data for year ended December 2007)

• Top 10 customers = 37% industrial 

sales* ($)

• Metropolitan areas account for 60% 

ultimate sales

• 8 persons per square mile (U.S. = 85)

• Industrial % is in terms of wires revenues

(data for 12 months ended December 2007)

AEP Texas North Company
52

Debt Equity Total Debt Equity Total Debt Equity Total

Capitalization Per Balance Sheet 276,845 316,276 593,121 276,936 308,705 585,641 302,386 334,244 636,630

% of Capitalization Per Balance Sheet 46.7% 53.3% 100.0% 47.3% 52.7% 100.0% 47.5% 52.5% 100.0%Adjusted Capitalization 276,845 316,276 593,121 268,785 308,705 577,490 303,682 334,244 637,926

% of Adjusted Capitalization 46.7% 53.3% 100.0% 46.5% 53.5% 100.0% 47.6% 52.4% 100.0%FFO Interest Coverage 5.0 3.7 4.7

FFO Total Debt 29.8% 17.4% 21.2%

2005 2006 2007

CAPITAL STRUCTURE (in thousands)

CAPITAL STRUCTURE

Revenue 280,000 $ 

% of AEP Retail 1%

Net Income 39,000 $ 

Capital Expenditure 88,000 $ 

2007 Financial Data * (in thousands)

As of 9/30/08

Total Assets 1,096,081 $ Net Plant Assets 954,938 $ 

Cash 214 $ 

2008 Asset Data ** (in thousands)

Sources: * 2007 Annual Report

** 3Q08 Financial Statements (unaudited)

Note: Capital Expenditure amounts exclude AFUDC

AEP Texas North Company
Operating Company

Overview Regulation

Generation &

Environmental Company Overview Coal
53

Regulation

Fall EEI 2008

• Regulatory Strategy

• Rate Case Filing Requirements

• Regulatory Activity Underway

• GridSMART Regulatory Status

• Rate Base and ROE by Operating Company

• Commission Overviews

54

Regulatory Strategy: Reduce Lag

The strategy: reduce the time between in-service dates and rate recovery Maximize frequency of filings

 Seek ability to pro-forma both capital and O&M through date which rates are effective

 Single-issue cost recovery

 Reliability Vegetation Environmental

 Trackers

 Federally-approved transmission costs Fuel and emissions ERO compliance costs Off-system sales margin sharing

 Formula rates Return on CWIP

Our goal is to maximize utility company cash flow and returns 

by minimizing regulatory lag.
55

Summary of Rate Case Filing Requirements

Regulatory framework inherently produces recovery and return lag.

Note 1: Post 1/1/09 no interim rates provided and rate cases must be filed no less than biennially; historical test year used. 

-- -- See note 1 -- -- -- -- -- -- 15 -- Period of Limitation (months)

No No Yes No No No No No No Yes No

GeneralTime Limitations Between CasesNotice of Intent

Yes No No No Yes Limited No Yes No No No Pancaking Permitted?

N/A 30 60 30 45 30 45 N/A 28 Varies 60 Notice Period (days)

No Yes Yes Yes Yes Yes Optional No Yes Yes Yes Prior PSC Notice Required?

Forecast 

Optional Historical Historical Historical Partially Projected Partially Projected Forecast Optional Historical Forecast Optional Historical Partially Projected

Case Components

Test Year

No

--

Indiana

6

Yes

Kentucky

Yes

10

Arkansas

Varies

Yes

Michigan

No

--

Louisiana

6

Yes

Oklahoma

9

Ohio

Yes

5

Yes

Virginia

5

Yes

Texas

No

--

West Virginia

OtherRates Effective Subject to RefundApprox # of Months after Filing to implement rates subject to refund

Yes

FERC

2 or 7
56

Regulatory Activity Underway

 AEP Ohio ESP Filing I&M - Indiana Base Rate Case PSO – Oklahoma Base Rate Case APCo - Virginia Base Rate Case SWEPCo Stall Plant Filings in Arkansas  SPP OATT Formula Rate Filing PJM OATT Formula Rate Filing 
57

Regulatory Activity Underway

 On July 31, 2008, in conjunction with the requirements of SB221, AEP Ohio filed an Electric 

Security Plan with the PUCO on behalf of CSPCo and OPCo.

 The filing includes the following key components:

 Energy Efficiency and Demand Response Renewable Energy gridSMARTSM Phase 1

 Distribution Reliability Enhancement Economic Development Provider of Last Resort

 The proposed rate plan results in an annual increase of approximately 15 percent on 

customers’ total bills.

 The filing seeks to recover changes in fuel and environmental expenses relative to levels 

reflected in current rates.

 Intervenor testimony was filed October 31, Staff testimony was filed November 7 and the 

public hearing commences on November 17, 2008. We anticipate an order in the first quarter of 2009.

AEP Ohio Electric Security Plan Filing
58

Summary Rate Case Information

I&M Indiana General Rate Case

On January 31, 2008, I&M filed a general base rate case with the Indiana Utility Regulatory Commission (IURC) requesting an increase of $125.6 million ($80.1 million in base revenues and $45.6 million in 

tracker mechanisms). (Docket #: 43306). Order is expected in June 2009. 

Projected Capital Structure – Company Position (9/30/07)

Procedural Schedule

% of 

Capitalization Cost Rate

Weighted 

Cost

Long-Term Debt 43.53% 5.98% 2.60%Preferred Stock 0.27% 11.19% 0.03%Common Equity 45.80% 11.50% 5.27%Other Items 10.40% various 0.20%

Total 100% 8.10%

Required Rate Relief – Company Position (9/30/07)

($ in millions)

January 31, 2008 Case filedMay-June 2008 Hearing presenting I&M Case-In-ChiefSeptember 2, 2008 Public & Intervenors' filing of Cases-In-ChiefOctober 15, 2008 Filing of rebuttal by I&MDecember 1, 2008 Hearing presenting public and intervenors' 

Cases-In-Chief and I&M rebuttal

Rate Base 1,999.1 $ *Rate of Return 8.10%Operating Income Requirement 161.9 $ 

Pro-Forma Operating Income 113.1 $ 

Difference 48.8 $ Revenue Conversion Factor 1.64Revenue Deficiency 80.1 $ Reliability Enhancement Tracker 28.4 $ DSM / EE Tracker 4.4 $ Off-System Sales Margins Tracker (48.0) $ PJM Tracker 44.4 $ Environmental Compliance Tracker 16.3 $ 

Total Required Rate Relief 125.6 $ 

* rate base as of September 30, 2007, updated for 

value of plant additions to the hearing date of May 5, 

2008
59

Summary Rate Case Information

PSO Oklahoma General Rate Case

On July 11, 2008, PSO filed a general base rate case with the Oklahoma Corporation Commission (OCC)

requesting an increase of $132.6 million. (Docket #: PUD 200800144). Order is expected in 1Q2009. 

Projected Capital Structure – Company Position 

(2/29/08)

Procedural Schedule

Required Rate Relief – Company Position (2/29/08)

($ in millions)

% of 

Capitalization Cost Rate

Weighted 

Cost

Long-Term Debt 55.57% 6.60% 3.67%Preferred Stock 0.33% 4.02% 0.01%Common Equity 44.10% 11.25% 4.96%

Total 100% 8.64%

July 11, 2008 Case filedOctober 29, 2008 Staff and intervenor testimonyNovember 19, 2008 PSO rebuttal testimonyDecember 8, 2008 Hearing commencesJanuary 8, 2009 Interim rates effective, subject to refund1Q 2009 Final order

Rate Base 1,545.2 $ *

Rate of Return 8.64%Operating Income Requirement 133.5 $ Pro-Forma Operating Income 53.0 $ 

Difference 80.5 $ Revenue Conversion Factor 1.647045Total Required Rate Relief 132.6 $ 

* rate base as of February 29, 2008, updated for 

known and measurable adjustment through August 

31, 2008
60

Summary Rate Case Information

APCo Virginia General Rate Case

On May 30, 2008, Appalachian Power filed a general base rate case with the SCC requesting an 

increase of $207.9 million. Interim rates were effective on October 28, 2008, subject to refund with 

interest. On October 29, 2008, a settlement agreement was presented to the SCC for its consideration. The settlement allows for a revenue increase of $168MM based on a 10.2% ROE. We 

await a final order. (Docket #: PUE-2008-00046)

Projected Capital Structure – Company Position (6/30/08)

Procedural Schedule

Required Rate Relief – Company Position (12/31/07)

($ in millions)

% of 

Capitalization Cost Rate

Weighted 

Return

Short-Term Debt 2.97% 4.79% 0.14%Long-Term Debt 55.52% 6.35% 3.53%Preferred Stock 0.32% 4.35% 0.01%Common Equity 41.02% 11.75% 4.82%Other Items 0.17% 8.63% 0.02%

Total 100% 8.52%

May 30, 2008 Case FiledSeptember 26, 2008 Respondents TestimonyOctober 10, 2008 Staff TestimonyOctober 20, 2008 APCo Rebuttal TestimonyOctober 28, 2008 Rates Effective, Subject to RefundOctober 29, 2008 Hearings

Rate Base 2,415.1 $ *

Rate of Return 8.52%Operating Income Requirement 205.7 $ Adjusted Operating Income 79.2 $ 

Difference 126.5 $ 

Revenue Conversion Factor 1.64Total Required Rate Relief 207.9 $ 

* rate base as of December 31, 2007, updated for 

known and measurable changes through June 30, 

2008
61

Regulatory Activity Underway

 On June 22, 2007, PSO and SWEPCo filed revised tariff sheets for the AEP pricing 

zone of the SPP OATT.

 The revised tariff sheets seek to establish an up-to-date revenue requirement for 

transmission services over the PSO and SWEPCo facilitates and implement a transmission cost of service formula rate.

 The new rate is a formula rate that will be used to update the revenue requirements 

each May, with new rates effective each July 1.

 The current revenue requirement is $88.7MM and the new revenue requirement 

requested is $140MM. Approximately $10MM of the increase relates to 3rd party and 

the rest, if approved, would be recovered through retail jurisdictional filings in SWEPCo and PSO, as appropriate.

 We requested an effective date of September 1, 2007 for the revised tariff, which 

the FERC suspended for an additional five months, which extended the effective date to February 1, 2008, with rates subject to refund. 

 Settlement discussions are currently on-going. 

SPP OATT Formula Rate Filing (Docket #:ER07-1069-000)
62

Regulatory Activity Underway

 On July 31, 2008, the seven AEP East companies filed with the FERC to update the 

Open Access Transmission Tariff (OATT) rate and implement a formula transmission rate that will be updated annually to keep rates current with 

transmission investment.

 The new rate is a formula rate that will be used to update the revenue 

requirements each May, with new rates effective each July 1.

 The current revenue requirement is $507MM and the new revenue requirement 

requested is $606MM. Approximately $31MM of the increase relates to 3rd party 

and Ohio and the rest, if approved, would be recovered through retail jurisdictional filings in the other east jurisdictions.

 We requested an effective date of October 1, 2008 for the revised tariff, which 

the FERC suspended for an additional five months, which extended the effective date to March 1, 2009, with rates subject to refund. 

PJM OATT Formula Rate Filing (Docket #:ER08-1329-000)
63

Regulatory Activity Underway

SWEPCo Turk Plant Filings

Arkansas On December 8, 2006, SWEPCo filed with the Arkansas Public Service Commission an 

Application for a Certificate of Environmental Compatibility and Public Need for the construction of a coal-fired baseload generating facility in Hempstead County, Arkansas.

 The PSC issued its order on November 21, 2007, approving construction of the plant.

 Air permit anticipated in the fourth quarter of 2008.Louisiana

 On August 25, 2006, SWEPCo filed with the Louisiana Public Service Commission an application 

to purchase, operate, own and install peaking, intermediate and baseload generating facilities. The peaking facility has been addressed and the intermediate facility has been approved. The remaining baseload facility issue relates to the Turk Plant proposed for Hempstead County, Arkansas. 

 The LPSC issued its order on April 29, 2008, approving construction of the plant. 

Texas

 On February 20, 2007, SWEPCo filed with the Public Utility Commission of Texas a petition 

seeking Certificate of Convenience and Necessity authorization for a coal-fired power plant to be located in southwest Arkansas.

 The PUCT issued its order approving construction of the plant on August 12, 2008, with a cost 

cap of $1.52 billion and a cap on carbon dioxide at $28/ton through 2030. This order is currently under appeal in Texas. 
64

Regulatory Activity Underway

SWEPCo Stall Plant Filings

Arkansas

 Proceeding is pending.Louisiana On August 25, 2006, SWEPCo filed with the Louisiana Public Service Commission an 

Application to purchase, operate, own and install Peaking, Intermediate and Baseload Generating Facilities. The intermediate facility, known as the Stall Plant and sited in Shreveport, LA, was bifurcated from the original filing and had a procedural schedule established on January 9, 2008. 

 PSC approval was granted on September 10, 2008. Air permit received on March 20, 2008.Texas

 PUCT order approving plant was issued on March 8, 2007.
65

State Policy AEP Action Plans

gridSMARTSM Evolution – AEP East

SSB 221 provides targets and provisions for DSM/EE programs and supports infrastructure modernization.

Filed an Electric Security Plan (2008) which includes a model city pilot in NE Columbus and addresses DSM/EE programs. New 2 MW NaS battery in Bluffton will demonstrate use of storage to enhance a sub-transmission system.

Pending DSM filing in Indiana; rules being finalized. EE/DSM legislative goals recently established in Michigan.

Broadly focused South Bend Pilot includes AMI, distribution automation, demand response, prepaid meters. NaS battery installation in IN in 2008 to demonstrate storage with intermittent wind.

Kentucky’s commission rules regarding DSM/EE programs are the model we seek in other states. 

Existing programs are focused on low-income weatherization and heat pump programs for mobile homes with favorable recovery. AMR investment will defer new AMI for several years.

Legislative interest in Virginia beginning to drive regulatory activity in EE/DSM.

New 2 MW NaS battery in West Virginia will test dynamic islanding – supplying electricity while disconnected from the grid. AMR investments in Virginia and West Virginia will defer new AMI for several years. EE/DSM potential study initiated.

The eastern states are evolving in their positions regarding demand side management, 

energy efficiency and AMI investments.
66

State Policy AEP Action Plans

gridSMARTSM Evolution – AEP West

DSM proceedings currently underway. Heavily 

involved with Commission regarding rulemaking. 

Favorable recovery provisions proposed.

Current legislation allows concurrent cost recovery of DSM/EE programs and performance incentives for exceeding goals. Legislature expecting distribution service providers in ERCOT to file plans for smart meter deployment.

DSM/EE program costs are recoverable thru a rider in Texas and Arkansas and base rates in Louisiana. No current statutory support for AMI outside of Texas footprint.

Implementing aggressive EE/DSM programs to achieve targets of 15% and 20% (respectively) to reduce growth in demand in 2008 & 2009 in Texas. Continue quick-start DSM/EE in Arkansas. Submitted EE Potential Study to Louisiana Commission in October 2008.

Conducting Distribution Automation pilot in 

South Tulsa. In process of implementing 

quick start DSM/EE programs.

Implementing aggressive DSM/EE programs to achieve legislatively mandated targets of 15% and 20% to reduce growth in demand in 2008 & 2009 respectively. A deployment plan for smart meters was initiated as of 10/31/08.

Texas currently has the most progressive legislative stance with regards to supporting 

AMI. PSO and SWEPCo have active DSM/EE programs with Distribution Automation 

pilots proposed in each state.
67

Approved Rate Bases & ROEs and Current Rate Case Requests

Jurisdiction Requested Rate Base Requested ROE

I&M - Indiana $1,999MM 11.50%

PSO - Oklahoma $1,545MM 11.25%

APCO - Virginia $2,415MM 11.75%

Rate Case Requests on File

Jurisdiction Rate Base Approved ROE Effective Date

APCo-Virginia $2,022MM 10.00% 10/2/2006

APCo-West Virginia $1,656MM 10.50% 7/28/2006

Kentucky $858MM 10.50% 3/31/2006I&M-Indiana $1,805MM 12.00% 11/19/1993

I&M-Michigan $268MM 13.00% 4/1/1991PSO-Oklahoma $1,120MM 10.00% 10/9/2007

SWEPCo-Louisiana $577MM 10.565% * 8/1/2008

SWEPCo-Arkansas $408MM 10.75% 9/23/1999SWEPCo-Texas $474MM 15.70% 2/15/1983TCC-Texas $1,566MM 9.96% 6/1/2007

TNC-Texas $530MM 9.96% 6/1/2007* - represents midpoint of the ROE range approved in the formula rate case settled in April 2008.
68

Commission Overview

Arkansas Public Service Commission

AEP Regulated Electric UtilitiesSouthwestern Electric Power Co.

Daryl E. Bassett, Commissioner (Rep.), since 2003; current term ends in 2009. Former policy advisor for Governor. Governor’s state budget director (2002-2003). Investment Banker for First State Investments/Merrill Lynch Fenner and Pierce (1985-1995). Bachelor’s attained at Harding University (Business-Public Administration).Collette Honorable, Commissioner (Dem.), since 2008; current term ends in 2011. Commissioner Honorable is a member of NARUC and serves on the Electricity and Consumer Affairs Committees. She also serves on the Smart Grid Collaborative, a joint effort of NARUC and the FERC. Honorable obtained Paul Suskie, Chairman (Dem.),her Juris Doctorate from the University of Arkansas at Little Rock School of Law. 

since 2007; current term ends in 2013. Lawyer, North Little Rock, Arkansas City Attorney. Bachelor’s attained at 

University of Central Arkansas. Juris Doctorate at University of Arkansas at Little Rock School of Law. NARUC member including Committee on Energy 

The Arkansas Public Service Commission (APSC) is composed of 3 members. The Governor appoints the Commissioners as well as theCommissionersResources and the Environment and Committee on Consumer Affairs.

 Chairman. Governor 

Qualifications for CommissionersHuckabee has appointed all of the current commissioners.

Political Makeup: R: 1 D: 2 Term: 6 Years Appointed/Elected: Appointed

Commissioners

Number: 3

SWEPCo-AR provides service at regulated bundled rates in Arkansas. Arkansas has an active fuel pass-through clause. Arkansas has an OSS margin sharing 

mechanism and allows CWIP in rate base for a plant that is placed in service within six months after the end of the test year.

AEP Regulatory Status
69

Indiana Utility Regulatory Commission

Commission Overview

AEP Regulated Electric UtilitiesIndiana Michigan Power Co.

Greg Server, Commissioner (Rep.), since 2005; current term ends 2009. Former state senator since 1981 and before that served in the Indiana House of Representatives from 1972 to 1980. Served as chair of Senate Commerce Committee, which handled IURC and utility industry legislation. Served as Director of Administration for the Evansville Water and Sewer Utility. Masters degrees in political science and counseling from Indiana State University.David E. Ziegner, Commissioner (Dem.), since 1990; current term ends April 2011. Lawyer, staff attorney for Legislative Services Agency, General Counsel for IURC. Member, NARUC Committee on Electricity and Advisory Council of the Electric Power Research Institute. Law degree from the Indiana University Larry S. Landis, Commissioner (Rep.), School of Law in Indianapolis.

since 2002; current term ends June 2011. Former president of a marketing and communications agency, VP 

Jeffrey L. Golc, Commissioner (Dem.), Corporate Advertising, American Fletcher National Bank. Bachelor’s degrees in political science and economics.

since 2007; current term will expire in 2009. Former public affairs manager for the Kroger Company. Previous 

Deputy Commissioner for the Indiana Bureau of Motor Vehicles and the Indiana Department of Workforce Development. Bachelors and Masters degrees in 

David L. Hardy, Chairman (Rep.),communications from Indiana University.

since 2005; current term will expire April 2010. Commissioner Hardy is an attorney who has worked in private practice 

since 1997. Areas of expertise include negotiation, contracts, litigation, finance and administration. He has 35 years of regulatory experience at the state and federal levels. Bachelors degree and law degree from Indiana University.Five members, appointed by the Governor from among persons nominated by a legislatively mandated utility commission nominating Commissioners

committee; four-year, 

staggered terms, full-time positions. Not more than three of the members of the IURC shall be members of the same political party. At least one of the 

commissioners must be an attorney qualified to practice law before the Indiana Supreme Court. The Governor appoints one of the five as chairman. 

Qualifications for CommissionersRepublican Mitch Daniels was elected Governor on November 2, 2004.

Political Makeup: R: 3 D: 2 Term: 4 Years Appointed/Elected: Appointed

Commissioners

Number: 5

I&M provides retail electric service in Indiana at bundled rates approved by the IURC. Rates are set on a cost-of-service basis with a fuel recovery 

mechanism. A current full base rate case is in process with a final order expected in the first half of 2009. The rate case includes requests for riders 

AEP Regulatory Status

related to DSM, environmental, reliability, OSS and RTO costs.
70

Commission Overview

Kentucky Public Service Commission

AEP Regulated Electric UtilitiesKentucky Power Co.

KPCo provides service at regulated bundled rates in Kentucky. Kentucky has an environmental surcharge to recover approved environmental costs and it 

has an active fuel clause. Kentucky also has an OSS sharing mechanism and a monthly adjustment clause in place for DSM.

James W. Gardner, Commissioner (Rep.), AEP Regulatory Status

since 2008; current term expires June 2012. Prior to joining the PSC Mr. Gardner was a partner at the law firm 

Henry Watz Gardner & Sellars PLLC where he specialized in bankruptcy law. JD degree from the University of Kentucky College of Law.John W. Clay, Vice Chairman (Rep.), since 2006; current term expires June 2009. Former deputy secretary of the Kentucky Environmental and Public Protection Cabinet. Served as executive director of the Office of Alcohol Beverage Control in the Department of Public Protection. B.A. from Georgetown David L. Armstrong, Chairman (Dem.), College. Certified Public Accountant and member of the AICPA.

since 2008; current term expires June 2011. Former practicing attorney in private practice. J.D. from University of 

Typically three members, appointed by the goCommissionersLouisville Brandeis School of Law. Mr. Armstrong is also the former Mayor for the city of Louisville, KY (1999-2003).

vernor and confirmed by the state senate for four years, staggered terms, full-time positions. The governor 

appoints one of the three as chairman and another of the three as vice chairman to serve in the chairman’s absence. Not more than two members of the Qualifications for CommissionersKYPSC shall be of the same profession or occupation.

Political Makeup: R: 2 D:1 Term: 4 Years Appointed/Elected: Appointed

Commissioners

Number: 3
71

Louisiana Public Service Commission

Commission Overview

AEP Regulated Electric UtilitiesSouthwestern Electric Power Co.Lambert C. Bossiere, III (Dem.), since 2005; current term ends December 2010. B.S. Business Administration from Southern University. American University of Paris – International Trade Law – Paralegal Certificate. Former First City Court Constable for the City of New Orleans. Member of NARUC.C. Dale Sittig, (Dem.), since 1995; current term ends December 2010. Member, Louisiana House of Representatives, (1983-1995). Member, Chamber of James M. Field, (Rep.),Commerce.

since 1996; current term ends December 2012. Practicing attorney, member of Electrical Committee of NARUC. NFL contract 

Foster L. Campbell, (Dem.),advisor (1983-present), member, Sports Lawyers Association. Bachelor’s and Juris Doctorate from Louisiana State University.

since 2003; current term ends December 2008. Member, Louisiana State Senate (1976-2002). Independent insurance 

businessman and farmer, former school teacher and agricultural products salesman. Bachelor’s degree from Northwestern State University.

Jack A. Blossman, Jr. (Rep.), since 1997; current term ends December 2008. Practicing attorney, member of NARUC Gas Committee. Board member of The Louisiana Public Service Commission (LPSC) is composed of CommissionersParish National Bank, member, Lake Ponchartrain Basin Foundation. Juris Doctorate from Southern Law School.

five elected members. The commissioners serve overlapping terms of six years.

Qualifications for Commissioners

Political Makeup: R: 2 D: 3 Term: 6 Years Appointed/Elected: Elected

Commissioners

Number: 5

SWEPCo-LA provides service at regulated bundled rates in Louisiana. Louisiana has an active fuel pass-through clause and an OSS margin sharing 

mechanism. Formula rate plans are permitted in Louisiana including a potential for a partial CWIP return on new generation projects. A formula rate plan 

AEP Regulatory Status

was implemented August 1, 2008.
72

Michigan Public Service Commission

Commission Overview

AEP Regulated Electric UtilitiesIndiana Michigan Power Co.

Monica Martinez, Commissioner, (Dem.), since 2005; current term expires July 2011. Former Deputy Director of the Governor’s Legislative Affairs Division where she served as the Governor’s principal lobbyist. Previous to this, she served as an analyst for the Senate Democratic Office, where she specialized in 

technology and energy, human services and family law policy issues. Bachelor’s degree, University of Michigan.Steven A. Transeth, Commissioner, (Ind.) , since 2007; current term expires July 2009. Former assistant director and legal counsel for the Michigan Legislative Service Bureau, which included drafting legislation and providing legal counsel to the Michigan Senate and House of Representatives. Lawyer, Orjiakor N. Isiogu, Chairman (Dem.),private practice and with the Ingham County Prosecuting Attorney’s office.. J.D. from Thomas Cooley Law School.

since 2007; current term expires July 2013. Former Director of the Telecommunications Division of the MPSC. 

The Michigan Public Service Commission (MPSC) is composed of thCommissionersAssistant Attorney General in Michigan since 1989. Undergraduate and law degree from Wayne State University.

ree members appointed by the Governor with the advice and consent of the Senate. 

Commissioners are appointed to serve staggered six-year terms. No more than two commissioners may represent the same political party. One Qualifications for Commissionerscommissioner is designated as chairman by the Governor.

Political Makeup: D: 2 I: 1 Term: 6 Years Appointed/Elected: Appointed

Commissioners

Number: 3

Customer choice began January 2002. Generation was not deregulated. Retail rates were unbundled (though they continue to be regulated) to allow customers to evaluate generation costs. Michigan has an active fuel clause and return on CWIP can be included in base rates.AEP Regulatory Status
73

Ohio Public Utilities Commission 

Commission Overview

AEP Regulated Electric UtilitiesColumbus Southern Power Co.Ohio Power Co.On January 26, 2005, the PUCO approved Rate Stabilization Plans (RSP) for CSP and OPCo (the Ohio Companies). The plans provided, among other things, for CSP and OPCo to raise their generation rates by 3% and 7% respectively, in 2006, 2007 and 2008 and provided for additional generation rate increases of up to 4% per year based on the Ohio Companies supporting the need for additional revenues. Distribution rates in effect at 12/31/05 are frozen for OPCo and CSP until 12/31/08. Transmission rates are currently regulated by FERC as reflected in the OATT. SB221 allows that CSP and OPCo will have active fuel clauses effective January 1, 2009. An Electric Security Plan is currently on file with the PUCO for consideration before the end of 2008. The ESP requests a 

Valerie A. Lemmie, Commissioner, (Ind.) 

AEP Regulatory Status15% rate increase for all CSP and OPCo customers.

since 2006; term expires April 2011. Master’s degree in Urban Affairs and Public Policy Planning, Washington 

University. Served as city manager for Cincinnati, Dayton, and Petersburg, Va. Scholar-in-residence at the Kettering Foundation. Chair of the Board of Directors of the National Academy of Public Administration.Cheryl Roberto, Commissioner, (Dem.) since 2008; term expires April 2013. Prior to joining the PUC, Roberto was director of the City of Columbus PublicUtilities Department. Before entering the public sector, Commissioner Roberto worked as an assistant attorney general for the state of Ohio.

Commissioner Roberto received her B.A. with honors from Kent State University and her Juris Doctorate from the Moritz College of Law at The Ohio StateRonda Hartman Fergus, Commissioner, (Rep.) University.

since 1995; term expires April 2010. Lawyer, Ohio State; previously served on the PUCO staff as an 

administrative law judge in the Legal Department. Later served as the chief of Telecommunications, Water and Sewer Section of the Legal Department, 

Paul A. Centolella, and then chief of the Telecommunications Technical Staff. Member NARUC Committee on Consumer Affairs.

Commissioner, (Dem.) since 2007; term expires April 2012. Juris Doctor from the University of Michigan. From 1992-2007, worked as a 

senior economist in the Energy Solutions Group of Science Applications International Corporation. Former senior policy advisor and senior utility attorney 

Alan R. Schriber, Ph.D., Chairman, (Ind.) for the Office of the Ohio Consumers’ Counsel.

, since 1999; term expires April 2009. Economics professor, president of a radio broadcasting company, 

investment advisor. Previously served as commissioner on the PUCO from 1983-1989. Member NARUC Telecommunications Committee, National Governors’ Five members, appointed by the governor CommissionersAssociation Electricity Task Force, Harvard Electricity Policy Group.

and confirmed by the state senate; five year, staggered terms, full-time positions, commissioners shall be 

selected from the lists of qualified persons submitted to the governor by the PUC nominating council. Not more than three of the members of the PUCO shall be members of the same political party. The governor appoints one of the five as president, who serves at the pleasure of the governor until a 

Qualifications for Commissionerssuccessor has been designated. 

Political Makeup: R: 1 D: 2 I: 2 Term: 5 Years Appointed/Elected: Appointed

Commissioners

Number: 5
74

Commission Overview

Oklahoma Corporation Commission

AEP Regulated Electric UtilitiesPublic Service Company of Oklahoma

Bob Anthony, Commissioner, (Rep.), since 1989; current term expires January 2013. Member, NARUC. Served on the boards of the Oklahoma State, Oklahoma City, and South Oklahoma City chambers of commerce. Earned a M.Sc. from the London School of Economics, a M.A. from Yale University and an M.P.A. from the Kennedy School of Government at Harvard University.Jim Roth, Commissioner, (Dem.), since 2007;appointed by the governor to fill the seat opened by the resignation of Commissioner Bode; current term ends January 2011. Previously served various county governments for eight years. Juris Doctorate from Oklahoma City University School of Law.Jeff Cloud, Chairman (Rep.), since 2002; current term ends January 2009. Member, NARUC. Served as U.S. Congressman’s District Director. Served as the The Oklahoma Corporation Commission (OCC) is composed of thrCommissionersOklahoma City Mayor’s Chief of Staff. Law degree from Oklahoma City University.

ee commissioners who are elected by state-wide vote. Commissioners serve staggered sixyear terms so one commissioner vacancy occurs every two years. The election pattern was established when the Commission was created by the state 

Qualifications for Commissionersconstitution.

Political Makeup: R: 2 D: 1 Term: 6 Years Appointed/Elected: Elected

Commissioners

Number: 3

PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC. PSO’s rates are set on a cost-of-service basis. Fuel and purchased 

energy costs above the amount included in base rates are recovered by applying a fuel adjustment factor to retail kilowatt-hour sales. The factor is 

generally adjusted annually and is based upon forecasted fuel and purchased energy costs. Over or under collections of fuel costs for prior periods are 

returned to or recovered from customers when new annual factors are established. PSO has an OSS margin sharing mechanism and has rider mechanisms 

AEP Regulatory Status

currently approved for vegetation management and the new peaking facilities in-service in 2008.
75

Commission Overview

Tennessee Regulatory Authority

AEP Regulated Electric UtilitiesKingsport Power Co.

Mary W. Freeman, Director (Dem.), AEP Regulatory StatusNo deregulation legislation and no base rate freeze or cap. Tennessee has an active fuel clause.

since 2008; current term expires June 2011. Prior legislative director for Governor Bredesen, executive assistant to 

State Representative Lois DeBerry. B.A. Tennessee State University.Eddie Roberson, Ph.D, Director, (Dem.), since 2006; current term expires June 2010. Former Chief of Consumer Services Division of the Regulatory Authority; also served a year as the agency’s Executive Director. Served two terms on the Chattanooga City School Board. Ph.D in Public Administration Sara Kyle, Director (Dem.), from Tennessee State University.

since 1996; current term expires June 2012. Former assistant public defender until she was elected to the Memphis City Court 

bench. The longest serving director and only holdover from the previous Regulatory Authority. Law degree from Middle Tennessee State University.Tre Hargett, Chairman (Rep.), since 2008; current term expires 2012. Former Representative of House District 97. M.B.A. Memphis State University.The Tennessee Regulatory Authority (TRA) direCommissioners

ctors are appointed, one each, by the Governor, Lieutenant Governor (as Speaker of the Senate), Speaker of 

the House and one joint appointment by the three together, and are confirmed by the Tennessee General Assembly. The directors are appointed for sixQualifications for Commissionersyear terms, which all expired in June 2008; terms are now staggered.

Political Makeup: R: 1 D: 3 Term: 6 Years Appointed/Elected: Appointed

Commissioners

Number: 4
76

Commission Overview

Public Utility Commission of Texas

AEP Regulated Electric UtilitiesTexas Central Co.Texas North Co.Southwestern Electric Power Co.

Retail competition has been delayed by the PUCT in the SPP area of Texas (including SWEPCO). SWEPCO-TX has an active fuel pass-through clause as well 

as OSS margin sharing. In some circumstances, CWIP is allowed in rate base. TCC and TNC provide retail transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules. Transmission riders provide annual recovery dependent on the level of transmission 

AEP Regulatory Status

investment and ERCOT load growth rates. AFUDC is permitted in limited circumstances.

Kenneth W. Anderson, (Rep.) since September 2008; current term expires September 2011. Past Director of Governmental Appointments under Governor Perry. Prior to that Anderson served in private practice as a corporate attorney in the area of securities law and regulatory matters. He also served as a 

member of the Texas Securities Board from 1999-2006. Anderson holds a law degree from Southern Methodist University.Donna Nelson, Commissioner (Rep.), since August 2008; current term expires August 2009. Nelson served as a special assistant and advisor to Governor

Perry on energy, telecommunications and cable budget and policy issues. She previously served as director of the PUC telecommunication's section and legaladvisor to the PUC chairman. Nelson holds a law degree from Texas Tech University. Barry T. Smitherman, Chairman, (Rep.), since April 2004; current term expires August 2013. Attorney; Assistant DA; Public Finance Investment Banker. To be eligible for appointment, a commissionCommissionersReceived law degree from the University of Texas School of Law.

er must be: (1) a qualified voter; (2) a citizen of the United States; and (3) a representative of the general 

Qualifications for Commissionerspublic. Chairman appointed by the Governor.

Political Makeup: R: 3 Term: 6 Years Appointed/Elected: Appointed

Commissioners

Number: 3
77

Commission Overview

Virginia State Corporation Commission

AEP Regulated Electric UtilitiesAppalachian Power Co.

James C. Dimitri (Dem.), since 2008; current term expires 2014. Prior to being named Commissioner, Dimitri was in private practice in Richmond. From 1994 to 2000 he served as Senior Counsel, then General Counsel at the SCC. He was an assistant Attorney General from 1983 to 1987. Dimitri received his undergraduate degree in economics from the University of Virginia and his J.D. from the Boston University School of Law in 1976.

Mark C. Christie (Rep.), since 2004; current term expires 2010. Attorney, counsel to the Speaker of the House. Lawyer, private practice. Law degree CommissionersJudith Williams Jagdmann, Chairperson, (Rep.), from Georgetown.

since 2006; current term expires 2012. Law degree from T.C. Williams School of Law at the University of 

Richmond. Served as Deputy Attorney General for Civil Litigation Division from 1998 to 2005. Attorney General for Commonwealth of Virginia from 2005 to The Virginia State Corporation Commission (VSCC) is composed of three members elected by the General Assembly. Commissioners ar2006.

e elected to serve sixQualifications for Commissioners

year terms, staggered in two year increments. The chair rotates annually among the three commissioners on February 1.

Political Makeup: R: 2 D: 1 Term: 6 Years Appointed/Elected: Elected

Commissioners

Number: 3

APCo-VA provides retail electric service in Virginia at unbundled rates. In 2007, the General Assembly passed legislation re-establishing retail rate regulation in the Commonwealth. The opportunity for one rate case exists before December 31, 2008, which was filed May 30, 2008. The new legislation provides for biennial rate reviews beginning in 2009, sharing of off-system sales margins at a rate of a minimum of 25% retained by the company effective July 1, 2007 and a post-2008 rider for DSM, renewable programs and new generation. APCo-VA is entitled to annual rate changes to recover the incremental costs it incurs for transmission and distribution system reliability and compliance with state or federal environmental laws or regulations (known as the E&R rider). APCo-VA is entitled to adjustments to fuel rates to recover its actual fuel costs, the fuel component of its purchased power costs AEP Regulatory Status

and certain capacity charges. 
78

Commission Overview

Public Service Commission of West Virginia

AEP Regulated Electric UtilitiesAppalachian Power Co.Wheeling Power Co.

Jon W. McKinney, Commissioner (Dem.), since 2005; term expires June 2011. Currently on the board of directors of the NARUC and second VP of the MidAtlantic Conference of Regulated Utilities Commissioners. Formerly served as plant manager of Flexsys’ Nitro, W .V. operations, chairman of Chemical Industry Committee for W.V., board member of W.V. Chamber of Commerce, W.V. Manufacturer’s Association, Chemical Alliance Zone, W.V. Roundtable, Advantage Valle, St. Francis Hospital & Thomas Memorial Hospital.Michael A. Albert, Chairman (Rep.), since 2007; term expires June 2013. Served as a member in the Business Law Department of Jackson Kelly. President and Chairman of the board of directors of the Kanawha County Public Library. Bachelor’s degree and Doctorate of Jurisprudence, West Virginia University.

Edward H. Staats, Commissioner (Dem.), since 2003; term expires June 2009. Former Chief of Operations in the Governor's office. Former Chief Financial Officer of the Workers’ Compensation Division of the W.V. Bureau of Employment Programs. Certified Public Accountant in West Virginia and Georgia. The West Virginia Public Service Commission CommissionersBachelor’s degree, West Virginia University.

(WVPSC) consists of three members, appointed by the Governor, with the advice and consent of the senate. 

No more than two members of the commission may belong to the same political party. The Commissioners serve six year staggered terms, with one term expiring as of July 1 of each odd numbered year. One Commissioner is designated as Chairman of the Commission by the Governor. The Chairman serves as 

Qualifications for Commissionersthe chief fiscal officer of the Commission.

Political Makeup: R: 1 D: 2 Term: 6 Years Appointed/Elected: Appointed

Commissioners

Number: 3

APCo and Wheeling Power in WV provide retail electric service at bundled rates approved by the WV PSC. West Virginia has an active annual ENEC 

(Expanded Net Energy Cost) mechanism, which provides for a rate adjustment for fuel costs, among other items. West Virginia also has a special construction surcharge permitted, primarily related to environmental-related construction.

AEP Regulatory Status
Operating Company

Overview Regulation

Generation &

Environmental Company Overview Coal
79

Generation & 

Environmental

Fall EEI 2008

• Units

• Generation Statistics

• New Generation

• Environmental

• Future Potential Green House Gas 

Regulations

80

Domestic Generation

COMPANY MW Capacity

AEP Generating Co 2,466

Appalachian Power Co 6,290

Columbus Southern Power 3,701

Indiana Michigan Power Co 4,501

Kentucky Power Co 1,060

Ohio Power Co 8,478

Public Service of Oklahoma 4,581

Southwestern Electric Power Co 4,857

Texas North Co** 647

OVEC Capacity*** 986

Domestic IPPs 311

Wind Purchase Power Agreements 843

Total 38,721

** Includes 270 MW of mothballed / retired / decommissioned generation

*** AEP owns a 43.5% interest in Ohio Valley Electric Corporation (OVEC), which 

supplies the power requirements of a uranium enrichment plant near Portsmouth, Ohio,

owned by the DOE. 

Generation Capacity*

*Capacity amounts represent the nominal capacity (the number of MW expected to be 

produced on a routine basis).
81

Domestic Generation

Note: RFC regional reliability council was formerly known as ECAR

Plant Name Units State

Regional 

Reliability 

Council Fuel Type

Nominal 

Capacity 

(MW)

AEP Generating Company

Rockport 1 IN RFC Steam - Coal 1,320

Lawrenceburg 6 IN RFC 1,146

 2,466

Appalachian Power Company

Buck 3 VA RFC Hydro 5

Byllesby 4 VA RFC Hydro 8

Claytor 4 VA RFC Hydro 28

Leesville 2 VA RFC Hydro 9

London 3 WV RFC Hydro 12

Marmet 3 WV RFC Hydro 11

Niagara 2 VA RFC Hydro 1

Reusens 5 VA RFC Hydro 6

Winfield 3 WV RFC Hydro 15

Smith Mountain 5 VA RFC Pumped Storage 586

Amos 2 WV RFC Steam - Coal 2,033

Clinch River 3 VA RFC Steam - Coal 705 

Glen Lyn 2 VA RFC Steam - Coal 335

Kanawha River 2 WV RFC Steam - Coal 400 

Mountaineer 1 WV RFC Steam - Coal 1,320

Sporn 2 WV RFC Steam - Coal 300

Ceredo 6 WV RFC Natural Gas 516

 6,290

Columbus Southern Power Company

Beckjord (CCD) 1 OH RFC Steam - Coal 53 

Conesville (CCD) 4 OH RFC Steam - Coal 1,254

Picway (CCD) 1 OH RFC Steam - Coal 100

Stuart (CCD) 4 OH RFC Steam - Coal 604

Stuart (CCD) 4 OH RFC Oil 3

Zimmer (CCD) 1 OH RFC Steam - Coal 330

Waterford 4 OH RFC Natural Gas 850

Darby 6 OH RFC Natural Gas 507

 3,701

Indiana Michigan Power Company

Berrien Springs 12 MI RFC Hydro 5 

Buchanan 10 MI RFC Hydro 2

Constantine 4 MI RFC Hydro 1

Elkhart 3 IN RFC Hydro 2

Mottville 4 MI RFC Hydro 1

Twin Branch 6 IN RFC Hydro 4

Rockport 1 IN RFC Steam - Coal 1,300

Tanners Creek 4 IN RFC Steam - Coal 995

Cook 2 MI RFC Steam - Nuclear 2,191

 4,501
82

Domestic Generation

Note: RFC regional reliability council was formerly known as ECAR

Plant Name Units State

Regional 

Reliability 

Council Fuel Type

Nominal 

Capacity 

(MW)

Kentucky Power Company

Big Sandy 2 KY RFC Steam - Coal 1,060

Ohio Power Company

Racine 2 OH RFC Hydro 26

Amos 1 WV RFC Steam - Coal 867

Cardinal 1 OH RFC Steam - Coal 580

Gavin 2 OH RFC Steam - Coal 2,640

Kammer 3 WV RFC Steam - Coal 630

Mitchell 2 WV RFC Steam - Coal 1,560

Muskingum River 5 OH RFC Steam - Coal 1,425

Sporn 3 WV RFC Steam - Coal 750

 8,478
83

Domestic Generation

Plant Name Units State

Regional 

Reliability 

Council Fuel Type

Nominal 

Capacity 

(MW)

Public Service Company of Oklahoma

Tulsa 3 OK SPP Steam - Natural Gas 415 

Tulsa 3 OK SPP Oil 8

Riverside 2 OK SPP Steam - Natural Gas 928 

Riverside 2 OK SPP Steam - Natural Gas 150 

Riverside 1 OK SPP Oil 3

Northeastern (1&2) 4 OK SPP Steam - Natural Gas 940 

Northeastern 1 OK SPP Oil 3

Sothwestern 3 OK SPP Steam - Natural Gas 475 

Sothwestern 2 OK SPP Steam - Natural Gas 150 

Sothwestern 1 OK SPP Oil 2

Comanche 3 OK SPP Steam - Natural Gas 285 

Comanche 2 OK SPP Oil 4

Weleetka 3 OK SPP Steam - Natural Gas 195 

Weleetka 2 OK SPP Oil 4

Northeastern (3&4) 2 OK SPP Steam - Coal 910

Northeastern 1 OK SPP Oil 1

Oklaunion 1 TX ERCOT Steam - Coal 108

 4,581

Southwestern Electric Power Company

Arsenal Hill 1 LA SPP Steam - Natural Gas 110 

Lieberman 4 LA SPP Steam - Natural Gas 278 

Knox Lee 4 TX SPP Steam - Natural Gas 486 

Wilkes 3 TX SPP Steam - Natural Gas 897 

Lone Star 1 TX SPP Steam - Natural Gas 50 

Mattison 4 AR SPP Steam - Natural Gas 346 

Welsh 3 TX SPP Steam - Coal 1,584

Flint Creek 1 AR SPP Steam - Coal 264

Pirkey 1 TX SPP Steam - Lignite 580

Dolet Hills 1 LA SPP Steam - Lignite 262

 4,857
84

Domestic Generation

Plant Name Units State

Regional 

Reliability 

Council Fuel Type

Nominal 

Capacity 

(MW)

Texas Central Company

none

Texas North Company

Paint Creek (Retired) 4 TX ERCOT Steam - Natural Gas 238

Abilene (Retired) 1 TX ERCOT Steam - Natural Gas 18

Ft. Stockton (Decommissioned) 1 TX ERCOT Steam - Natural Gas 6

Vernon (Decommissioned) 4 TX ERCOT Oil 8

Oklaunion 1 TX ERCOT Steam - Coal 377

 647

Domestic Independent Power Projects

Trent Mesa 100 TX ERCOT Wind 150

Desert Sky 107 TX ERCOT Wind 161

 311

Long-Term Wind Purchase Power Agreements

Southwest Mesa TX ERCOT Wind 75

Weatherford OK SPP Wind 147

Blue Canyon II OK SPP Wind 151

Sleeping Bear OK SPP Wind 95

Camp Grove IL RFC Wind 75

Fowler Ridge IN RFC Wind 100

Fowler Ridge IN RFC Wind 100

Beech Ridge WV RFC Wind 100

843
85

Generation Statistics

* Super-critical includes coal units with a net maximum capacity of 450MW or greater; sub-critical includes coal units with a net maximum capacity less than 450MW. ** Includes all AEP owned Hydro and Pumped Storage generation.*** CF, EAF, and EFOR do not include Dolet Hills. Dolet Hills included in generation number as owned. Pirkey and Flint Creek reported as owned.  Oklaunion reported as owned.** *** East Gas Units evaluated using Equivalent Forced Outage Factor. Since these units are run less frequently, this factor gauges their performance based on Period Hours instead of Service Hours. EFOR uses Service Hours in the denominator, and EFOF uses Period Hours in the denominator.

Net Capacity Factors 2006 2007

Equivalent Availability Factors 2006 2007

Equivalent Forced Outage Rate (EFOR) 2006 2007

AEP East 64.57% 64.26% AEP East 81.80% 81.09% AEP East 8.54% 8.32%

 Coal 70.34% 71.89% Coal 80.29% 78.73% Coal 9.37% 9.02%

 Super Critical* 73.36% 73.00% Super Critical* 80.55% 77.93% Super Critical* 8.31% 8.81% Sub-Critical* 61.00% 68.44% Sub-Critical* 79.49% 81.23% Sub-Critical* 12.63% 9.62%

 Gas 2.58% 7.27% Gas 92.84% 90.19% Gas - See Below

 Hydro** 10.68% 7.85% Hydro** 92.30% 86.42% Hydro** 4.99% 11.61% Nuclear 83.55% 90.86% Nuclear 82.87% 89.68% Nuclear 0.65% 1.25%

AEP SPP 45.10% 43.20% AEP SPP 86.25% 84.79% AEP SPP 6.79% 6.75%

 Coal*** 76.87% 77.45% Coal*** 82.87% 82.35% Coal*** 3.86% 5.49%

 Super Critical* 83.77% 78.10% Super Critical* 86.76% 80.41% Super Critical* 5.50% 6.20% Sub-Critical* 75.02% 77.21% Sub-Critical* 81.67% 83.09% Sub-Critical* 3.31% 5.23%

 Gas 23.33% 20.65% Gas 88.56% 86.39% Gas 9.73% 8.04%

AEP Texas 65.35% 71.95% AEP Texas 67.78% 73.95% AEP Texas 23.48% 17.43%

 Coal**** 65.35% 71.95% Coal  67.78% 73.95% Coal** ** 23.48% 17.43%

AEP System 60.06% 59.54% AEP System 82.62% 81.84% AEP System 8.45% 8.13%

Equivalent Forced Outage Factor (EFOF) 2006 2007

AEP East Gas***** 0.39% 1.23%
86

Net Generation Statistics

Notes: Figures represent generation produced from AEP-owned assets only.

Net Generation By Operating Company (in MWhs)

Operating Company 2006 2007

AEP Generating 10,276,134 9,027,362Appalachian Power 31,494,581 32,588,773

Columbus Southern Power 14,134,232 15,514,495

Indiana Michigan Power 31,950,768 31,604,874

Kentucky Power 7,171,505 7,533,223

Ohio Power 49,341,134 54,155,697

Public Service of Oklahoma 15,139,848 14,439,801

Southwestern Electric Power 19,961,798 19,673,059

Texas Central Company 309,085 41,122

Texas North Company 2,160,348 2,309,566

AEP System Total Net Generation 181,939,433 186,887,972
87

New Generation

Operating 

Company Project Name State Projected Cost Fuel Type Plant Type

MW 

Capacity

Commercial 

Operation Date 

AEG Dresden Ohio $309 MM Gas Combined-cycle 580 2010

SWEPCo Stall Louisiana $378 MM Gas Combined-cycle 500 2010SWEPCo Turk Arkansas $1.5 B (1) Coal Ultra-supercritical 600 (1) 2012

(1) SWEPCo will own approximately 73%, or 440 megawatts, totaling about $1,110 million in capital investment. The increase in the cost estimate relates to cost escalations due to the delay in receipt of permits and approvals.
88

Environmental
89

Much of this investment will position AEP to accomplish the following:

 Reduce nitrogen oxide emissions by 90% through installation of Selective Catalytic 

Reduction (SCR) systems

 Reduce sulfur dioxide emissions by 95% to 98%+ through installation of Flue Gas 

Desulfurization (FGD) systems (scrubbers) 

 Realize co-benefit of mercury capture offered through SCR and FGD systems together 

 Avoid future landfill costs through sale of gypsum (by-product) & build where landfill 

costs are lower

 Realize benefits achieved through fuel flexibility

NOx and SO2 emission reductions are part of AEP’s on-going strategy to 

comply with the Clean Air Act, Title IV regulations and the NSR consent 

decree executed in October 2007.

AEP’s Environmental Compliance Strategy

Represents the best and least-cost compliance path to improve 

environmental performance on a fleet basis, while continuing to 

provide a reliable supply of power to customers at a reasonable 

price and a solid return for investors.
90

• Rule finalized March 2005• Designed to address the contribution of regional emissions 

to downwind PM2.5 & 8-hour Ozone non-attainment

• Reductions from 2003-level emissions: ~73% SO2 & ~61% NOx

• Reductions occur in phases: Phase I (2009/2010); Phase II (2015)• Established three cap & trade programs:

1. Annual SO2 Trading Program

2. Annual NOx Trading Program

3. Separate Ozone-Season only NOx Trading Program

• On July 11, 2008 the D. C. Circuit Court issued a decision to remand and vacate CAIR, 

but the decision is not yet final

• EPA and others have requested rehearing, and the D. C. Circuit Court has requested 

further briefing on whether any party requested that the rule be vacated, and whether the rule should remain in place while EPA responds to the remand

• A final decision is expected shortly after the briefing is completed (November 2008)

Clean Air Interstate Rule

Applicability to AEP• AEP-East States & Louisiana subject to all three trading programs

• Arkansas subject only to the Ozone-Season trading program

• Texas subject to only the Annual NOx & SO2 trading programs

• CAIR does not apply to Oklahoma
91

• Rule finalized March 2005• Designed to address the Clean Air Act’s best available retrofit technology 

(BART) requirements and applicability to plants built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants

• Final rule demonstrates that CAIR will result in more visibility 

improvements than BART

• States are allowed to substitute CAIR requirements in their SIPs for 

controls that would otherwise be required by BART

• For BART-eligible facilities located in states not subject to CAIR 

requirements for SO2 and NOx, additional controls will be required

Clean Air Visibility Rule

Applicability to AEP• Requires SO2 reductions in Oklahoma and Arkansas

• Scrubbers (FGDs) will be installed at our Northeastern and Flint Creek 

plants by 2015
92

• Rule finalized March 2005• Designed to reduce mercury emissions by ~70% nationwide 

from electric utilities

• Reductions occur in phases: Phase I (2010); Phase II (2018)• Establishes a cap & trade structure to achieve mercury 

reductions

• On February 8, 2008 the Supreme Court issued a decision to 

remand and vacate CAMR

Clean Air Mercury Rule

AEP will achieve significant mercury reduction as a co-benefit of 

SCR and FGD systems, but mercury specific control equipment will

be needed on several units.
93

Generation - Environmental Project Status Report

At the conclusion of our current environmental retrofit program, over 58% of our 24,630 MW coalfired generation fleet will be equipped with SCRs and over 73% will be scrubbed (FGDs).

Plant Name

MW 

Capacity SCR Status FGD Status

East Plants

Amos 1 800  In-service  Projected 2010

Amos 2 800  In-service  Projected 2009

Amos 3 1300  In-service  Projected 2009

Big Sandy 2 800  In-service  Projected 2014

Cardinal 1 600  In-service  In-service

Conesville 5 375 N/A  Upgrade In-service

Conesville 6 375 N/A  Upgrade in-service

Gavin 1&2 2620  In-service  In-service; Upgrade projected 2010Mitchell 1&2 1600  In-service  In-service

Mountaineer 1320  In-service  In-service

Muskingum River 5 585  In-service  Projected 2015

Rockport 1 1300  Projected 2017  Projected 2017Rockport 2 1300  Projected 2019  Projected 2019

CCD Plants

Conesville 4 339  Projected 2009  Projected 2009

Stuart 1-4 620  In-service  In-service

Zimmer 330  In-service  In-service

West Plants

Dolet Hills 262 N/A  In-service; Upgrade projected 2012

Flint Creek 1 264 N/A  Projected 2012

Northeastern 3 450 N/A  Projected 2012

Northeastern 4 450 N/A  Projected 2013

Oklaunion 485 N/A  In-service

Pirkey 580 N/A  Upgrade In-serviceWelsh 2 528 N/A  Projected 2012
94

Materials and Vendors – AEP’s Advantage

Actuals To Date & Firm Costs

5%

95%

Estimated Cost Exposure*

Breakdown of Environmental Compliance Program

(% of Purchased Costs) SCR Technology

FGD Technology

• Removes 85 – 93% of NOx emissions• Requires ~ 1% use of auxiliary power• AEP Capital Cost ~ $162/kW avg.• Removes 95 – 98% of SO2 emissions• Requires ~1.5% to 3.0% use of auxiliary 

power

• AEP Capital Cost ~ $262/kW avg.

Note: these percentages relate to the environmental program through 2010* Primarily labor costs

Combination of SCR & FGD 

technology results in co-benefit of Hg 

removal ~ 80% removal efficiency

AEP benefits from first-mover advantage through lower contracted 

prices compared to industry.
95

• The overall generation loss in capacity associated with SCR 

and FGD retrofit for the entire AEP fleet is roughly 600MW.

• Typically, an SCR consumes approximately 1% whereas an 

FGD consumes from 1.5% to 3.0% of the plant electricity output.

• Plant modifications increasing unit MW ratings are being 

implemented as part of the retrofit program• For example, Mountaineer turbine valve upgrades will 

increase unit output by ~30 - 45 MW

• Similar upgrades will be implemented on other units

Impact of SCR and FGD on Net Generation

Plant modifications will mitigate FGD and SCR capacity 

consumption.
96

Calendar Year Limitation

2010 450,000 tons2011 450,000 tons2012 420,000 tons2013 350,000 tons2014 340,000 tons2015 275,000 tons2016 260,000 tons2017 235,000 tons2018 184,000 tons

2019 and each year thereafter 174,000 tons

Eastern System-Wide Annual Tonnage Limitations for SO2

Emission Limits

In compliance with our 2007 NSR settlement, 

the following limits are applicable to 

AEP’s eastern generation fleet:

Calendar Year Limitation

2009 96,000 tons2010 92,500 tons2011 92,500 tons2012 85,000 tons2013 85,000 tons2014 85,000 tons2015 75,000 tons

2016 and each year thereafter 72,000 tons

Eastern System-Wide Annual Tonnage Limitations for NOx

Emissions caps do not include any of the gas-fired units, or any new units AEP might build or purchase in the east.
97

AEP/CertainTeed Gypsum Wallboard Initiative

 CertainTeed Gypsum opened new 

wallboard manufacturing plant in March of 2008 adjacent to OPCo’s Mitchell plant near Moundsville, WV

 Wallboard plant utilizes the gypsum 

produced from both the Mitchell and Cardinal power plants.

 Gypsum is the by-product of the recently completed FGD (i.e. scrubber) process. Key Project Benefits

 Environmental stewardship program which 

eliminates the need for an expensive gypsum landfill at Mitchell.

 Significant capital and annual O&M savings 

for Ohio ratepayers.

 Wallboard is produced using greater than 96% recycled materials (i.e. gypsum, paper). Created many new good paying jobs. Strong/stable counterparty – CertainTeed is 

the #1 producer of wallboard in the world
98

Future Potential Green House 

Gas Regulations
99

AEP’s Climate Position

 AEP supports a reasonable approach to carbon controls in the US AEP has taken measurable, voluntary actions to reduce its GHG 

emissions and will support a well-thought out US mandate to achieve additional, economy-wide reductions

 Global warming is a global issue and AEP supports the US taking a 

leadership role in developing a new international approach that will address growing emissions from all nations, including developing countries such as India and China

 A certain and consistent national policy for reasonable carbon 

controls should include the following principles:

 Comprehensiveness Cost-effectiveness Realistic emission control objectives Monitoring, verification and adjustment mechanisms Technology development & deployment

 Regulatory or economic barriers must be addressed Recognition provided for early action/investment made for GHG 

mitigation

 Inclusion of adjustment provision if largest emitters in developing 

world do not take action

A reliable and reasonably-priced electric supply is necessary to 

support the economic well-being of the areas we serve.
100

AEP’s Long-term CO2 Reduction Commitment

Existing Programs

 Renewables

 800 MWs of Wind 300 MWs of Hydro

 Domestic Offsets

 Forestry – 0.35MM tons/yr @ 

$500K/year

 Over 63MM trees planted 

through 2006

 1.2MM tons of carbon 

sequestered

 International Offsets

 Forestry projects have 

resulted in 1MM tons of carbon sequestered through 2006

 Chicago Climate Exchange

New Program Additions Incremental Reduction quantity: 5MM tons/yr Timing: To take effect/receive credits by 2011  Methods

 +1000 MWs of Wind PPAs – 2MM tons/yr Domestic Offsets (methane) – 2MM tons/yr 

(e.g., livestock methane capture deal of 0.6MM tons/yr)

 Forestry – Tripling annual investment to 

increase to 0.5MM tons/yr by 2015 

 Fleet Vehicle/Aviation Offsets – 0.2MM tons/yr Additional actions to include DSM and end use 

energy efficiency, biomass and power plant efficiency – 0.2MM tons/yr

New Technology Additions Commercial solutions for existing fleet

 Chilled Ammonia

AEP is committed to a 5mm ton/yr reduction in CO2 emissions 

which offsets approx half of the emissions projected from new 

generation projects previously announced.
101

Chilled Ammonia Technology Program

Project Validation 20-30 MWe (megawatts electric) scale (a 

scale up of Alstom/EPRI 1.7 MWe field 

pilot, under construction at WE Energies)

 Located at the AEP Mountaineer Plant in 

WV

 100,000 – 300,000 tonnes CO2 per year

 In operation 3Q 2009 Alstom “Chilled Ammonia” Technology Geologic storage for CO2

Represents Post-Combustion Capture Conventional or Advanced Amines; 

Chilled Ammonia

 Amine technologies are currently 

commercially available in other industrial applications

 Relatively low CO2 concentration 

in flue gas – more difficult to capture than other approaches

 High parasitic demand

 Conventional Amine ~ 25-30% Chilled Ammonia target ~ 

10-15%

2009 Commercial Operation

Mountaineer 

Plant (WV)

CO2 Storage 

(Battelle)

MOU (Alstom & RWE)

Post-combustion carbon solution provides pure CO2 stream 

for capture.

Chilled 

Ammonia
Operating Company

Overview Regulation

Generation &

Environmental Company Overview Coal
102

Coal

Fall EEI 2008

• Coal Procurement, Delivery & Transportation

• Fuel Recovery

• Coal Market Information

103

Coal Procurement – 2008 Projected

Coal Stats: 100% contracted for 2008 Avg. delivered price ~ $36.58/ton in 2007 Approximate 28% price increase in 2008 

based on 2007 actual results. 

AEP burns approx. 76 million tons 

of coal per year

Northern 

Appalachia

33%

Powder River Basin 

34%

Central 

Appalachia

24%

AEP West

Lignite

28%

Powder River 

Basin

72%

AEP East

Northern 

Appalachia

45%

Powder River 

Basin

20%

Central 

Appalachia

33%

Total AEP System

Lignite 8% Colorado/Utah 1%

Colorado/Utah 2%
104

Total AEP System

Barge Direct

22%

Rail/

Barge*

15%

Truck

8%

Belt/Conveyor

11% Rail Direct

40%

Rail Direct

74%

Belt/Conveyor

26%

Barge Direct

30%

Rail Direct

28%

Rail/

Barge*

21%

Truck

11%

* Reflects coal delivered to AEP plants transported through a combination of rail and barge

2007 Actual

AEP East AEP West

Coal Delivery

Truck Combo

4%

Truck 

Combo

5%

Belt/Conveyor

5%
105

AEP’s Coal Transportation Assets

 Current Coal & Transportation Assets:

 Control over 9,000 railcars Own/lease and operate over 2,900

barges & 80 towboats/tugs

 Coal handling terminal with 20 

million tons of capacity

*Represents close approximations

2007 Actual

AEP’s transportation assets provide flexibility in a constrained 

delivery environment.

25%

75%

AEP-owned Asset External Carrier

Coal Transportation to AEP Plants*
106

AEP River Operations

• Full-service Inland Waterways carrier

 2,900 hopper barges 60+ towboats/20 tugs

• Tonnage & Commodity: 

 Captive: (for AEP)-37MM tons of coal;  Commercial: 35MM tons of coal/grain/bulk

• Gulf Operations

Barge cleaning and repairFleeting and shiftingMidstream transfers

• Operating Centers in Lakin, WV, Cape 

Girardeau, MO, Paducah, KY, Convent and Belle Chase, LA

Inland Waterway Routes For AEP River Operations
107

Off System Sales 

Counterparties

25%

Shareholder

20%

Customer

55%

AEP System

 In response to Ohio Substitute Senate Bill 221, AEP Ohio 

filed an Electric Security Plan that would allow recovery of fuel costs from customers who do not switch their supplier. If adopted, AEP’s fuel costs will be eligible for recovery in all AEP jurisdictions beginning in 2009.

 80% of fuel cost is recoverable across the AEP System Active Fuel Clause Jurisdictions: 

– AEP EAST: APCo, I&M, KPCo, KGP, WP– AEP WEST: PSO, SWEPCO

Note: Fuel recovery percentages are based on estimates for 2008 fiscal year

Fuel Cost Recovery

(on average)

Fuel Recovery
108

Jurisdictional Fuel Clause Summary

ArkansasIndianaKentuckyLouisianaMichiganOhioOklahomaTennesseeTexas (SPP)VirginiaWest Virginia

YesYesYesYesYes

Effective 1/1/09

YesYesYesYesYes

Annually

Semi-Annually

MonthlyMonthly

Annually

TBD

Annually

Monthly

AnnuallyAnnuallyAnnually

Jurisdiction Active Fuel Clause Frequency

Effective January 1, 2009 we have fuel recovery in all jurisdictions.
109

Coal Producing Regions 

Illinois

Basin

• Medium Btu; High Sulfur• Market needs development

Northern

Appalachia

• High Btu; High Sulfur• Market Concentration

Central

Appalachia

• High Btu; Low Sulfur• Fragmented Market• Production Hurdles

Southern PRB

• Low Btu; Low Sulfur• Market Concentration• Transportation to the East

CO/UT

Uinta

Basin

• High Btu; Low Sulfur• Limited transportation
110

Uses of Coal by Sector
111

Domestic Coal Price Markers (FOB Mine)

$90.00$80.00$70.00$60.00$50.00$40.00$30.00$20.00

$150.00$140.00$130.00$120.00$110.00$100.00

January-03 May 03 - Sept me ber 03 - January 04 -May-04 September-04 January-05 May 05 - Sept me ber 05 - January-06 May-06 Sept me ber 06 - January-07 May-07 September-07 January-08May 08 - Sept me ber 08 -

n NYMEX Price, $/to

$25.00$23.00$21.00$19.00$17.00$15.00$13.00$11.00$9.00$7.00$5.00

PRB Price, $/ton

NYMEX Prompt Mo.PRB 8800 Prompt Mo.
112

Domestic Coal Market 

Primary drivers for increasing coal prices in the US are: Increase in the cost components to produce the product Declining productivity due to reserves, safety, etc. Declining eastern US coal production....particularly Central Appalachia

 Increasing global demand for coal....particularly Asia Inability to bring on new production quickly due to permitting and labor related issues High cost to mine in Central Appalachian region Capital required for new production Sustained pricing, how long? Increase in the international demand for US coal products

 Dramatic increase in east coast and gulf coast US coal exports have lead to much higher priced 

markets in the US (82M exp; 28M imp)

 Continued demand of metallurgical coal is drawing steam coal into the metallurgical coal market Weak US Dollar
Financial Update Transmission Initiatives
113

Transmission Initiatives

Fall EEI 2008

114

NOTE: The lines shown are conceptual in nature and do not represent actual routes. Plans are subject to change.

Making it Happen: EHV Projects Under Development

NEW 765

Potential 

PJM Projects

Potential 

PJM Projects

SPP EHV 

Overlay (2008)

SPP EHV 

Overlay (2008)

MISO Vision 

Plan (2008)

MISO Vision 

Plan (2008)

Existing AEP Existing AEP 

765-kV System 765-kV System AEP/ITC 

Project

AEP/ITC 

Project

PATH PATH 

Project Project

AEP/Duke AEP/Duke
115

765 Right-of-Way Comparison

From a siting standpoint, 765-kV is more efficient in terms of economies 

of scale and right-of-way than lower capacity lines.
116

EHV Transmission in PJM: PATH

The ROW routes shown on this diagram are illustrative of the initial project approved by PJM, and not of the recently reconfigured line. As such, this map is not intended to depict the actual route that will eventually be selected. 

 PATH Progress to Date

 PJM approved project in its Regional Transmission 

Expansion Plan in June 2007

 On September 1, 2007 AEP and Allegheny Energy formed a 

new joint venture -- Potomac-Appalachian Transmission Highline (PATH) and its subsidiaries

 FERC order issued on February 29, 2008 approving:

 Cash return on CWIP and 14.3% incentive ROE Recovery of all costs incurred prior to the time rates go into 

effect, and

 Recovery of all prudently incurred development and 

construction costs if the project is abandoned as a result of factors beyond the control of PATH or its parents.

 FERC ordered the formula rate mechanism be set for 

hearing, pending settlement judge procedures

 In October 2008, PJM announced a reconfiguration of the 

PATH line which will eliminate the connection with the Bedington substation and the twin-circuit 500-kV lines from Bedington to Kemptown, and include a new mid-point substation near existing PATH alternative routes

 The reconfiguration is a result of constraints identified as a 

result of comprehensive siting studies; interaction with government agencies; public input; and a desire to identify a solution that reduces line mileage and minimizes the impact on communities and the environment.

 Total estimated cost of $1.8 billion; AEP portion 

approximately $600 million

 Key Challenges

 CPCN and Siting Approval from WV and MD
117

Joint Ventures with MidAmerican Energy Holdings Company

 50/50 utility joint venture between AEP Utilities, 

Inc. and MEHC Texas Transco, LLC

 ETT capital structure is 60% debt / 40% equity 

with a 9.96% ROE

 Services provided by AEP and investment 

opportunities can be offered by either partner

 Total initial investment of $70 million before 

ownership division

 In October 2008, the District Court found that the 

PUCT exceeded its authority by granting ETT a CCN. This decision is currently under appeal and ETT believes the ultimate outcome will validate its utility status.

 AEP signed an agreement with MidAmerican 

Energy Holdings Company on September 13, 2007 to form Electric Transmission America, a 50/50 joint venture.

 Both MidAmerican and AEP desire to utilize ETA 

as a vehicle to invest in select transmission projects located in North America, outside the Electric Reliability Council of Texas.

 Projects taken on by ETA would entail 

transmission facilities:

 345 kV and above Within, adjacent to and outside the 

Companies’ respective service areas (excluding ERCOT)

 Greater than $100 million 

 ETA is working on identifying investment 

opportunities and collaborating with likeminded, qualified investment partners in different regions of the country.

 In 2008, ETA signed agreements with 

Westar Energy and OGE proposing to build the first and second segments of the 765-kV Overlay Plan in SPP

Electric Transmission Texas Update Electric Transmission America Update
118

Texas CREZ Project

The ROW routes shown on this diagram are for illustrative purposes only and may not depict the actual route that could eventually be selected. The substation locations may also be modified. 

 Overview

 In September 2008, ETT and a 

group of other Texas transmission providers filed a comprehensive plan with the PUCT for completion of the CREZ facilities approved by the Commission.

 ETT’s requested share of the 

coordinated plan is approximately $1.5 billion. Staff testimony in October 2008 recommended ETT’s share at $1.2 billion.

 The filing calls for completion of 

the plan by 2012.

 Next Steps

 PUCT hearings – December 2008 Selection of transmission 

providers – 1Q 2009

Strengthening the ERCOT grid to collect and deliver wind generation to load
119

EHV Transmission in SPP

Total SPP 765-kV Overlay estimated to cost approximately $7 Billion by SPP March 2008 study, a portion of which could be built by ETA. The ROW routes shown on this diagram are for illustrative purposes only and may not depict the actual route that could eventually be selected. The substation locations may also be modified. 

 Overview

 Sent non-binding Letter of Commitment to 

SPP to construct 765-kV and 500-kV projects in SPP region consistent with SPP Overlay Study – Summer 2007

 Updated EHV Overlay Study completed by 

SPP – March 2008

 Benefits

 Overall reliability reinforcement with 

improved voltage support throughout the SPP system

 Significantly increased transfer capability Provides access to new generation resources, 

especially renewables

 Allows for effective interconnections for EHV 

system development

Significant opportunity for 765-kV transmission in SPP
120

Prairie Wind Transmission, LLC

Westar

Total SPP 765-kV Overlay estimated to cost approximately $7 Billion by SPP March 2008 study, a portion of which could be built by ETA. The ROW routes shown on this diagram are for illustrative purposes only and may not depict the actual route that could eventually be selected. The substation locations may also be modified. 

Westar

 Overview

 In May 2008, ETA signed an agreement with 

Westar Energy to form Prairie Wind Transmission, LLC (PWT).

 PWT is a 50/50 JV that is proposing to build 

approximately 230 miles of 765-kV lines extending from Wichita, KS, west to a substation northeast of Dodge City, KS, and then south to the Kansas border from Medicine Lodge, KS. 

 The project will provide enhanced electricity 

transport in Kansas and support expansion of renewable electricity generation in the region.

 Project is expected to cost approximately $600 

million (based on SPP estimates) and be inservice by 2013.

 AEP’s ownership of the joint venture is 25%. Kansas CPC filing submitted in May 2008. FERC formula rate filing submitted in October 

2008 requesting:

 Cash return on CWIP and 13.3% incentive ROE Recovery of all costs incurred prior to the time 

rates go into effect, and

 Recovery of all prudently incurred development 

and construction costs if the project is abandoned as a result of factors beyond the control of PWT or its parents.

JV to build first segment of 765-kV transmission in SPP

 Key Challenges

 Cost allocation which enables the development of 

“system solutions”

 RTO Approval
121

Tallgrass Transmission, LLC

Total SPP 765-kV Overlay estimated to cost approximately $7 Billion by SPP March 2008 study, a portion of which could be built by ETA. The ROW routes shown on this diagram are for illustrative purposes only and may not depict the actual route that could eventually be selected. The substation locations may also be modified. 

OGE

 Overview

 In July 2008, ETA signed an agreement with 

Oklahoma Gas & Electric to form Tallgrass Transmission, LLC (TG).

 TG is a 50/50 JV that is proposing to build 

approximately 170 miles of 765-kV lines extending from the Kansas-Oklahoma border north of Woodward, OK, extending west into the Oklahoma panhandle to a new station that will be built near Guymon, OK. 

 The project will promote wind development in the 

western half of Oklahoma.

 Project is expected to cost approximately $500 

million and be in-service by 2013.

 AEP’s ownership of the joint venture is 25%. Other responsibilities will be handled by the 

partners or outsourced.

 FERC formula rate filing submitted in October 

2008:

 Cash return on CWIP and 13.3% incentive ROE Recovery of all costs incurred prior to the time 

rates go into effect, and



JV to build second segment of 765-kV transmission in SPP

Recovery of all prudently incurred development and construction costs if the project is abandoned as a result of factors beyond the control of TG or its parents.

 Key Challenges

 Cost allocation which enables the development of 

“system solutions”

 RTO Approval
122

Pioneer Transmission, LLC

The ROW routes shown on this diagram are for illustrative purposes only and may not depict the actual route that could eventually be selected. 

 Overview

 In August 2008, AEP signed an agreement with 

Duke Energy to form Pioneer Transmission, LLC (PT).

 PT is a 50/50 JV that is proposing to build 

approximately 240 miles of 765-kV lines extending from AEP’s Rockport Station to Duke’s Greentown station in Indiana.

 The project will improve the reliability of the 

nation's transmission grid, allow more efficient use of existing electricity production and delivery infrastructure, protect national security and expand opportunities for new generation, including renewables. 

 Project is expected to cost approximately $1 

billion and be in-service by 2015.

 AEP’s ownership of the joint venture is 50%. Other responsibilities will be handled by the 

partners or outsourced.

 FERC formula rate filing submitted in October 

2008 requesting:

 Cash return on CWIP and 13.5% incentive ROE Recovery of all costs incurred prior to the time 

rates go into effect, and

 Recovery of all prudently incurred 

development and construction costs if the project is abandoned as a result of factors beyond the control of PT or its parents.

 Key Challenges

 Cost allocation which enables the development of 

“system solutions”

 RTO Approval Siting
123

EHV Transmission in Michigan 

The ROW routes shown on this diagram are for illustrative purposes only and may not depict the actual route that could eventually be selected. The substation locations may also be modified. 

 Overview

 ITC and AEP conducted a technical study for a 

new 765-kV from Ohio to Michigan 

 Study was released Q3 2007 700 miles of 765-kV line in Ohio and Michigan $2.6 billion investment (in 2007$, before 

ownership division)

 AEP and ITC are in discussions to form a Joint 

Venture

 Benefits

 Up to 5,000 MW improved transfer capability Reduces network line losses by 250 MW

 Key Challenges

 Cost allocation which enables the development of 

“system solutions”

 RTOs Approvals

Supporting Michigan’s 21st Century Energy Plan to address severe capacity constraints
Financial Update Transmission Initiatives
124

Financial Update

Fall EEI 2008

• Capitalization

• Liquidity Position

• Credit Ratings

• Long-Term Debt Maturity Profile

• Debt Schedules

125

Capitalization

Our goal remains a maximum 60/40 debt-to-capital ratio on an adjusted 

basis.

Capital Structure

Debt Equity Total Debt Equity Total

Balance Sheet CapitalizationLong-term Debt 14,993 - 14,993 16,007 16,007

Short-term Debt 660 - 660 1,302 1,302

Preferred Stock Not Subject to Mandatory Redemption - 61 61 61 61

Common Equity - 10,079 10,079 10,917 10,917

Total Capitalization per Balance Sheet 15,654 10,139 25,793 17,309 10,978 28,286

% of Capitalization per Balance Sheet 60.7% 39.3% 100.0% 61.2% 38.8% 100.0%

Adjustments

Defeased First Mortgage Bonds (19) - (19) - - - 

less: Cash and Marketable Securities (178) - (178) (781) - (781)

Capital and Operating Leases 1,522 - 1,163 1,470 - 1,470

Securitization Bonds (2,257) - (2,257) (2,132) - (2,132)

Receivables Securitization 507 - 507 555 - 555

Spent Nuclear Fuel Disposal Liability (259) - (259) (263) - (263)

Equity Portion of Hybrid Issuances - - - (158) 158 1

Total Adjusted Capitalization 14,969 10,139 25,108 15,999 11,136 27,135

% of Adjusted Capitalization 1 59.6% 40.4% 100.0% 59.0% 41.0% 100.0%

Credit Adjusted Ratios:

 FFO Interest Coverage 4.3 4.7

 FFO to Total Debt 19.6% 21.5%

Actual 12/31/2007 Actual 9/30/2008
126

Liquidity

AEP’s liquidity position is $2.7 billion as of 10/28/08.

Liquidity Summary Actual(unaudited) 10/28/08

($ in millions) Amount Maturity

Revolving Credit Facility $1,500 Mar-11Revolving Credit Facility 1,454 Apr-12Revolving Credit Facility 627 Apr-11Revolving Credit Facility 338 Apr-09

Total Credit Facilities 3,919

Plus

AEP, Inc. Cash and Investments 1,366

Less 

Draw on Credit Facilities (1,969)Commercial Paper Outstanding (178)Letters of Credit Issued (439)

Net Available Liquidity $2,699
127

AEP Credit Ratings

S BBB+ S BBB N Baa1 Southwestern Electric Power CompanyS BBB+ S BBB S Baa1 Public Service Company of OklahomaS BBB+ S BBB N A3 Ohio Power CompanyS BBB S BBB S Baa2 Kentucky Power CompanyS BBB S BBB S Baa2 Indiana Michigan Power CompanyS A- S BBB S A3 Columbus Southern Power Company

N BBB+ S BBB N Baa2 Appalachian Power Company

S A- S BBB S Baa1 AEP Texas North CompanyS BBB+ S BBB N Baa2 AEP Texas Central CompanyS F2 S A2 S P2 AEP, Inc. Short Term RatingS BBB S BBB S Baa2 American Electric Power Company Inc.

Outlook Unsecured Outlook Unsecured Outlook Unsecured Company

Senior Senior Senior

Fitch S&P Moody's

Current Ratings for AEP, Inc. & Subsidiaries

Ratings current as of October 17, 2008
128

Long-term Debt Maturity Profile

Year 2008 (1) 2009 2010

AEP, Inc. $ - $ - $ 490

AEP Generating Company $ - $ - $ -

Appalachian Power $ - $ 150 150 $ 

Columbus Southern Power $ - $ - $ 150

Kentucky Power $ 30 $ - $ -

Indiana Michigan Power $ 50 $ - $ -

Ohio Power $ 37 $ 600 82 $ 

Public Service of Oklahoma $ - $ 150 50 $ 

Southwestern Electric Power $ - $ - $ -

Texas Central Company(2) $ - $ - $ 203

Texas North Company $ - $ - $ -

Total $ 117 $ 1,743 282 $ 

(1) Maturities remaining as of September 30, 2008

(2) Includes Texas Securitization Bonds Based upon Scheduled Final Payment Date

($ in millions)
129

Debt Schedules

Note: Debt schedules current as of 9/30/08.

American Electric Power, Inc Interest Maturity Amount

Junior Subordinated Debentures 8.750% 03/01/2063 $315,000,000

Senior Notes 5.375% 03/15/2010 $490,000,000

Senior Notes 5.250% 06/01/2015 $242,775,000

Weighted Average or Total 6.36% $1,047,775,000

AEP Generating Interest Maturity Amount

Pollution Control Bond 4.150% 07/01/2025 $22,500,000

Pollution Control Bond 4.150% 07/01/2025 $22,500,000

Senior Notes 6.330% 06/28/2037 $210,909,170

Weighted Average or Total 5.947% $255,909,170
130

Debt Schedules

Note: The weighted average coupon excludes all floating rate debt.

Debt schedules current as of 9/30/08.

AEP Texas Central Interest Maturity Amount

Pollution Control Bond 5.625% 10/01/2017 $40,890,000

Pollution Control Bond 4.450% 06/01/2020 $6,330,000

Pollution Control Bond 5.200% 05/01/2030 $60,000,000

Pollution Control Bond 4.400% 05/01/2030 $111,700,000

Pollution Control Bond 4.550% 05/01/2030 $50,000,000

Pollution Control Bond 5.125% 06/01/2030 $120,265,000

Preferred Stock 4.000% NA $4,191,200

Preferred Stock 4.200% NA $1,730,100

Senior Notes 6.650% 02/15/2033 $275,000,000

Weighted Average or Total 5.609% $670,106,300

Securitization Bond 5.560% 01/15/2010 $85,906,616

Securitization Bond 5.960% 07/15/2013 $214,926,738

Securitization Bond 6.250% 01/15/2016 $191,856,858

Weighted Average or Total 6.003% $492,690,212

Securitization Bond 4.980% 01/01/2010 $116,771,724

Securitization Bond 4.980% 07/01/2013 $341,000,000

Securitization Bond 5.090% 07/01/2015 $250,000,000

Securitization Bond 5.170% 01/01/2018 $437,000,000

Securitization Bond 5.306% 07/01/2020 $494,700,000

Weighted Average or Total 5.146% $1,639,471,724

AEP Texas North Interest Maturity Amount

Pollution Control Bond 4.450% 06/01/2020 $44,310,000

Preferred Stock 4.400% NA $2,348,600

Senior Notes 5.500% 03/01/2013 $225,000,000

Senior Notes 5.890% 04/01/2018 $30,000,000

Senior Notes 6.760% 04/01/2038 $70,000,000

Weighted Average or Total 5.637% $371,658,600
131

Debt Schedules

Note: The weighted average coupon excludes all floating rate debt.

Debt schedules current as of 9/30/08.

Appalachian Power Company Interest Maturity Amount

Pollution Control Bond 4.850% 05/01/2019 $30,000,000

Pollution Control Bond 4.850% 05/01/2019 $40,000,000

Pollution Control Bond Floating 11/01/2021 $17,500,000

Pollution Control Bond 5.000% 11/01/2021 $19,500,000

Pollution Control Bond 5.500% 10/01/2022 $100,000,000

Pollution Control Bond 6.050% 12/01/2024 $30,000,000

Pollution Control Bond Floating 02/01/2036 $50,275,000

Pollution Control Bond Floating 02/01/2036 $75,000,000

Preferred Stock 4.500% NA $17,752,000

Senior Notes 6.600% 05/01/2009 $150,000,000

Senior Notes 4.400% 06/01/2010 $150,000,000

Senior Notes 5.550% 04/01/2011 $250,000,000

Senior Notes 5.650% 08/15/2012 $250,000,000

Senior Notes 4.950% 02/01/2015 $200,000,000

Senior Notes 5.000% 06/01/2017 $250,000,000

Senior Notes 5.950% 05/15/2033 $200,000,000

Senior Notes 5.800% 10/01/2035 $250,000,000

Senior Notes 6.375% 04/01/2036 $250,000,000

Senior Notes 6.700% 08/15/2037 $250,000,000

Senior Notes 7.000% 04/01/2038 $500,000,000

Weighted Average or Total 5.91% $3,080,027,000
132

Debt Schedules

Note: Debt schedules current as of 9/30/08.

Columbus Southern Power Interest Maturity Amount

Pollution Control Bond Floating 12/01/2038 $48,550,000

Pollution Control Bond Floating 12/01/2038 $43,695,000

Pollution Control Bond 4.850% 08/01/2040 $44,500,000

Pollution Control Bond 5.100% 11/01/2042 $56,000,000

Senior Notes 4.400% 12/01/2010 $150,000,000

Senior Notes 5.500% 03/01/2013 $250,000,000

Senior Notes 6.050% 05/01/2018 $350,000,000

Senior Notes 6.600% 03/01/2033 $250,000,000

Senior Notes 5.850% 10/01/2035 $250,000,000

Weighted Average or Total 5.751% $1,442,745,000

Indiana Michigan Power Company Interest Maturity Amount

Pollution Control Bond Floating 10/01/2019 $25,000,000

Pollution Control Bond Floating 11/01/2021 $52,000,000

Pollution Control Bond 5.250% 04/01/2025 $40,000,000

Pollution Control Bond 4.625% 06/01/2025 $50,000,000

Pollution Control Bond Floating 06/01/2025 $50,000,000

Pollution Control Bond Floating 06/01/2025 $50,000,000

Preferred Stock 4.125% NA $5,533,500

Preferred Stock 4.120% NA $1,105,500

Preferred Stock 4.560% NA $1,441,200

Senior Notes 6.450% 11/10/2008 $50,000,000

Senior Notes 6.375% 11/01/2012 $100,000,000

Senior Notes 5.050% 11/15/2014 $175,000,000

Senior Notes 5.650% 12/01/2015 $125,000,000

Senior Notes 6.000% 12/31/2032 $150,000,000

Senior Notes 6.050% 03/15/2037 $400,000,000

Weighted Average or Total 5.778% $1,275,080,200
133

Debt Schedules

Note: The weighted average coupon excludes all floating rate debt.

Debt schedules current as of 9/30/08.

Kentucky Power Interest Maturity Amount

Senior Notes 6.450% 11/10/2008 $30,000,000

Senior Notes 6.000% 09/15/2017 $325,000,000

Senior Notes 5.625% 12/01/2032 $75,000,000

Weighted Average or Total 5.966% $430,000,000

Ohio Power Company Interest Maturity Amount

Pollution Control Bond Floating 07/01/2014 $50,000,000

Pollution Control Bond Floating 07/01/2014 $50,000,000

Pollution Control Bond Floating 04/01/2022 $35,000,000

Pollution Control Bond Floating 06/01/2022 $50,000,000

Pollution Control Bond 5.563% 10/01/2022 $19,565,000

Pollution Control Bond 5.563% 01/01/2023 $19,565,000

Pollution Control Bond 5.150% 05/01/2026 $50,000,000

Pollution Control Bond Floating 04/01/2028 $54,500,000

Pollution Control Bond Floating 07/01/2028 $54,500,000

Pollution Control Bond Floating 10/01/2028 $54,500,000

Pollution Control Bond Floating 01/01/2029 $54,500,000

Pollution Control Bond Floating 04/01/2036 $65,000,000

Pollution Control Bond 4.900% 06/01/2037 $65,000,000

Notes Payable 6.270% 03/31/2009 $1,000,000

Notes Payable 7.490% 04/15/2009 $70,000,000

Notes Payable 7.210% 06/15/2009 $11,000,000

Preferred Stock 4.080% NA $1,459,500

Preferred Stock 4.200% NA $2,282,400

Preferred Stock 4.400% NA $3,148,200

Preferred Stock 4.500% NA $9,737,300

Senior Notes 6.240% 12/04/2008 $37,225,000

Senior Notes Floating 04/05/2010 $400,000,000

Senior Notes 5.300% 11/01/2010 $200,000,000

Senior Notes 5.500% 02/15/2013 $250,000,000

Senior Notes 5.750% 09/01/2013 $250,000,000

Senior Notes 4.850% 01/15/2014 $225,000,000

Senior Notes 6.000% 06/01/2016 $350,000,000

Senior Notes 6.600% 02/15/2033 $250,000,000

Senior Notes 6.375% 07/15/2033 $225,000,000

Weighted Average or Total 5.812% $2,907,982,400
134

Debt Schedules

Note: The weighted average coupon excludes all floating rate debt.

Debt schedules current as of 9/30/08.

Public Service Company of Oklahoma Interest Maturity Amount

Pollution Control Bond Floating 06/01/2014 $33,700,000

Pollution Control Bond 4.450% 06/01/2020 $12,660,000

Preferred Stock 4.000% NA $4,454,800

Preferred Stock 4.240% NA $806,900

Senior Notes 4.700% 06/15/2009 $50,000,000

Senior Notes 4.850% 09/15/2010 $150,000,000

Senior Notes 4.700% 05/15/2011 $75,000,000

Senior Notes 6.150% 08/01/2016 $150,000,000

Senior Notes 6.000% 12/31/2032 $200,000,000

Senior Notes 6.625% 11/15/2037 $250,000,000

Weighted Average or Total 5.791% $926,621,700

Southwestern Electric Power Company Interest Maturity Amount

Notes Payable 4.470% 05/16/2011 $11,381,290

Notes Payable 4.470% 05/16/2011 $11,748,427

Notes Payable 7.030% 02/22/2012 $20,000,000

Notes Payable 6.370% 10/31/2024 $25,000,000

Pollution Control Bond 4.500% 07/01/2011 $41,135,000

Pollution Control Bond 4.950% 03/01/2018 $81,700,000

Pollution Control Bond Floating 01/01/2019 $53,500,000

Preferred Stock 5.000% NA $3,767,300

Preferred Stock 4.650% NA $190,700

Preferred Stock 4.280% NA $738,600

Senior Notes 5.375% 04/15/2015 $100,000,000

Senior Notes 4.900% 07/01/2015 $150,000,000

Senior Notes 5.550% 01/15/2017 $250,000,000

Senior Notes 5.875% 03/01/2018 $300,000,000

Senior Notes 6.450% 01/15/2019 $400,000,000

Trust Preferred Stock 5.250% 10/01/2043 $113,403,000

Weighted Average or Total 5.708% $1,562,564,317

Grand Total $16,102,631,623